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 estimated to be approximately $14 million payable by EFH Corp. to the IRS. Pursuant to the Tax Matters Agreement, Vistra Energy had an obligation to reimburse EFH Corp. 50% of the estimated alternative minimum tax, and approximately $7 million was reimbursed during the three months ended June 30, 2017. In October 2017, the 2016 federal tax return that included the results of EFCH, EFIH, Oncor Holdings and TCEH was filed with the IRS and resulted in a $3 million payment from EFH Corp. to Vistra Energy. The spin-off transaction resulted in Vistra Energy, including the TCEH Debtors and the Contributed EFH Debtors, no longer being an affiliate of EFH Corp. and its subsidiaries.

Separation Agreement

On the Effective Date, EFH Corp., Vistra Energy and a subsidiary of Vistra Energy entered into a separation agreement that provided for, among other things, the transfer of certain assets and liabilities by EFH Corp., EFCH and TCEH to Vistra Energy. Among other things, EFH Corp., EFCH and/or TCEH, as applicable, (a) transferred the TCEH Debtors and certain contracts and assets (and related liabilities) primarily related to the business of the TCEH Debtors to Vistra Energy, (b) transferred sponsorship of certain employee benefit plans (including related assets), programs and policies to a subsidiary of Vistra Energy and (c) assigned certain employment agreements from EFH Corp. and certain of the Contributed EFH Debtors to a subsidiary of Vistra Energy.

Tax Matters Agreement

On the Effective Date, Vistra Energy and EFH Corp. entered into 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.

Settlement Agreement

The Debtors, the Sponsor Group, certain settling TCEH first lien creditors, certain settling TCEH second lien creditors, certain settling TCEH unsecured creditors and the official committee of unsecured creditors of the TCEH Debtors entered into a settlement agreement (the Settlement Agreement) in August 2015 (as amended in September 2015 and approved by the Bankruptcy Court in December 2015) to settle, among other things, (a) intercompany claims among the Debtors, (b) claims and causes of actions against holders of first lien claims against TCEH and the agents under the TCEH Senior Secured Facilities, (c) claims and causes of action against holders of interests in EFH Corp. and certain related entities and (d) claims and causes of action against each of the Debtors' current and former directors, the Sponsor Group, managers and officers and other related entities.

Tax Matters

In July 2016, EFH Corp. received a private letter ruling from the IRS in connection with our emergence from bankruptcy, which provides, among other things, for certain rulings regarding the qualification of (a) the transfer of certain assets and ordinary course operating liabilities to Vistra Energy and (b) the distribution of the equity of Vistra Energy, the cash proceeds from Vistra Energy debt, the cash proceeds from the sale of preferred stock in a newly formed subsidiary of Vistra Energy, and the right to receive payments under a tax receivables agreement, to holders of TCEH first lien claims, as a reorganization qualifying for tax-free treatment.

Pre-Petition Claims

On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases and discharged approximately $33.8 billion in LSTC. Initial distributions related to the allowed claims asserted against the TCEH Debtors and the Contributed EFH Debtors commenced subsequent to the Effective Date. As of December 31, 2018, the TCEH Debtors have approximately $52 million in escrow to (1) distribute to holders of currently contingent and/or disputed unsecured claims that become allowed and/or (2) make further distributions to holders of previously allowed unsecured claims, if applicable. Additionally, the TCEH Debtors have approximately $5 million in escrow to pay remaining professional fees incurred in the Chapter 11 Cases. The remaining contingent and/or disputed claims against the TCEH Debtors consist primarily of unsecured legal claims, including asbestos claims. These remaining claims and the related escrow balance for the claims are recorded in Vistra Energy's consolidated balance sheet as other current liabilities and current restricted cash, respectively. A small number of other disputed, de minimis claims that are asserted as being entitled to priority and/or against the Contributed EFH Debtors, if allowed, will be paid by Vistra Energy, but all non-priority unsecured claims, including asbestos claims arising before the Petition Date, will be satisfied solely from the approximately $52 million in escrow.

Predecessor Reorganization Items

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the 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 Predecessor period from January 1, 2016 through October 2, 2016 as reported in the statements of consolidated income (loss):



	Predecessor
	Period from January 1, 2016 through October 2, 2016
Gain on reorganization adjustments (Note 6)	$	(24,252	)
Loss from the adoption of fresh start reporting	2,013
Expenses related to legal advisory and representation services	55
Expenses related to other professional consulting and advisory services	39
Contract claims adjustments	13
Other	11
Total reorganization items	$	(22,121	)

Fresh-Start Reporting (Notes)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Fresh-Start Reporting

FRESH START REPORTING

As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of ASC 852. In order to apply fresh-start reporting, ASC 852 requires two criteria to be satisfied: (1) that total post petition liabilities and allowed claims immediately before the date of confirmation of the Plan of Reorganization be in excess of reorganization value and (2) that holders of our Predecessor's voting shares immediately before confirmation of the Plan receive less than 50% of the voting shares of the emerging entity. Vistra Energy met both criteria. Under ASC 852, application of fresh start reporting is required on the date on which a plan of reorganization is confirmed by a bankruptcy court and all material conditions to the plan of reorganization are satisfied. All material conditions to the Plan of Reorganization were satisfied on the Effective Date, including the execution of the Spin-Off.

Reorganization Value

A third-party valuation specialist submitted a report to the Bankruptcy Court in July 2016 assuming an emergence from bankruptcy as of December 31, 2016. This report provided an estimated value range for the total Vistra Energy enterprise. Management selected an enterprise value within that range of $10.5 billion. The enterprise value submitted by the valuation specialist was based upon:


•	historical financial information of our Predecessor for recent years and interim periods;


•	certain internal financial and operating data of our Predecessor;


•	certain financial, tax and operational forecasts of Vistra Energy;


•	certain publicly available financial data for comparable companies to the operating business of Vistra Energy;


•	the Plan of Reorganization and related documents;


•	certain economic and industry information relevant to the operating business, and


•	other studies, analyses and inquiries.

The valuation analysis for Vistra Energy included (i) a discounted cash flow calculation and (ii) peer group company analysis. Equal weighting was assigned to the two methodologies, before adding the value of the tax basis step-up resulting from certain transactions pursuant to the Plan of Reorganization, which was valued separately. The estimated future cash flows included annual forecasts through 2021. A terminal value was included in the discounted cash flow calculation using an exit multiple approach based on the cash flows of the final year of the forecast period.

The valuation analysis used a discount rate of approximately 7%. The determination of the discount rate takes into consideration the capital structure, credit ratings and current debt yields of comparable publicly traded companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry.

Although the Company believes the assumptions and estimates used by the valuation specialist to develop the enterprise value are reasonable and appropriate, different assumption and estimates could materially impact the analysis and resulting conclusions.

Under ASC 852, reorganization value is generally allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill. Vistra Energy estimates its reorganization value of assets at approximately $15.161 billion as of October 3, 2016, which consists of the following:



Business enterprise value	$	10,500
Cash excluded from business enterprise value	1,594
Deferred asset related to prepaid capital lease obligation	38
Current liabilities, excluding short-term portion of debt and capital leases	1,123
Noncurrent, non-interest bearing liabilities	1,906
Vistra Energy reorganization value of assets	$	15,161

Consolidated Balance Sheet

The adjustments to TCEH's October 3, 2016 consolidated balance sheet below include the impacts of the Plan of Reorganization and the adoption of fresh start reporting.



	October 3, 2016
	TCEH (Predecessor) (1)		Reorganization Adjustments (2)				Fresh Start Adjustments				Vistra Energy (Successor)
ASSETS
Current assets:
Cash and cash equivalents	$	1,829	$	(1,028	)	(3)	$	—			$	801
Restricted cash	12		131			(4)	—				143
Trade accounts receivable — net	750		4				—				754
Advances to parents and affiliates of Predecessor	78		(78		)		—				—
Inventories	374		—				(86		)	(17)	288
Commodity and other derivative contractual assets	255		—				—				255
Margin deposits related to commodity contracts	42		—				—				42
Other current assets	47		17				3				67
Total current assets	3,387		(954		)		(83		)		2,350
Restricted cash	650		—				—				650
Advance to parent and affiliates of Predecessor	17		(21		)		4				—
Investments	1,038		1				9			(18)	1,048
Property, plant and equipment — net	10,359		53				(5,970		)	(19)	4,442
Goodwill	152		—				1,755			(27)	1,907
Identifiable intangible assets — net	1,148		4				2,256			(20)	3,408
Commodity and other derivative contractual assets	73		—				(14		)		59
Deferred income taxes	—		320			(5)	730			(21)	1,050
Other noncurrent assets	51		38				158			(22)	247
Total assets	$	16,875	$	(559	)		$	(1,155	)		$	15,161
LIABILITIES AND EQUITY
Current liabilities:
Long-term debt due currently	$	4	$	5			$	(1	)		$	8
Trade accounts payable	402		145			(6)	3				550
Trade accounts and other payables to affiliates of Predecessor	152		(152		)	(6)	—				—
Commodity and other derivative contractual liabilities	125		—				—				125
Margin deposits related to commodity contracts	64		—				—				64
Accrued income taxes	12		12				—				24
Accrued taxes other than income	119		4				—				123
Accrued interest	110		(109		)	(7)	—				1
Other current liabilities	243		170			(8)	5				418
Total current liabilities	1,231		75				7				1,313



	October 3, 2016
	TCEH (Predecessor) (1)			Reorganization Adjustments (2)				Fresh Start Adjustments				Vistra Energy (Successor)
Long-term debt, less amounts due currently	—			3,476			(9)	151			(23)	3,627
Borrowings under debtor-in-possession credit facilities	3,387			(3,387		)	(9)	—				—
Liabilities subject to compromise	33,749			(33,749		)	(10)	—				—
Commodity and other derivative contractual liabilities	5			—				3				8
Deferred income taxes	256			(256		)	(11)	—				—
Tax Receivable Agreement obligation	—			574			(12)	—				574
Asset retirement obligations	809			—				854			(24)	1,663
Other noncurrent liabilities and deferred credits	1,018			117			(13)	(900		)	(25)	235
Total liabilities	40,455			(33,150		)		115				7,420
Equity:
Common stock	—			4			(14)	—				4
Additional paid-in-capital	—			7,737			(15)	—				7,737
Accumulated other comprehensive income (loss)	(32		)	22				10			(26)	—
Predecessor membership interests	(23,548		)	24,828			(16)	(1,280		)	(26)	—
Total equity	(23,580		)	32,591				(1,270		)		7,741
Total liabilities and equity	$	16,875		$	(559	)		$	(1,155	)		$	15,161


(1)	Represents the consolidated balance sheet of TCEH as of October 3, 2016.

Reorganization adjustments


(2)	Includes the addition of certain assets and liabilities associated with the Contributed EFH Entities. Also includes EFH Corp.'s contribution of liabilities associated with certain employee benefit plans to Vistra Energy.


(3)	Net adjustments to cash, which represent distributions made or funding provided to an escrow account, classified as restricted cash, under the Plan of Reorganization, as follows:



Sources (uses):
Net proceeds from PrefCo preferred stock sale	$	69
Addition of cash balances from the Contributed EFH Debtors	22
Payments to TCEH first lien creditors, including adequate protection	(486		)
Payment to TCEH unsecured creditors (including $73 million to escrow)	(502		)
Payment of administrative claims to TCEH creditors	(53		)
Payment of legal fees, professional fees and other costs (including $52 million to escrow)	(78		)
Net use of cash	$	(1,028	)


(4)	Increase in restricted cash primarily reflects amounts placed in escrow to satisfy certain secured claims, unsecured claims and professional fee obligations associated with the bankruptcy.


(5)	Reflects the deferred income tax impact of the Plan of Reorganization implementation, including cancellation of debts and adjustment of tax-basis for certain assets of PrefCo that issued mandatorily redeemable preferred stock as part of the Spin-Off.


(6)	Primarily reflects the reclassification of transmission and distribution service payables to Oncor from payables with affiliates to trade payables with third parties pursuant to the separation of Vistra Energy from EFH Corp. and payment of accrued professional fees and unsecured claimant obligations incurred in conjunction with Emergence.


(7)	Primarily reflects the payment of accrued interest and adequate protection to the TCEH first lien creditors on the Effective Date.


(8)	Primarily reflects the following:


•	Reclassification of $82 million from LSTC related to secured and unsecured claims and $16 million in accrued professional fees from accounts payable to other current liabilities.


•	Additional accruals for $23 million of change-in-control obligations and $26 million in success fees triggered by Emergence, $7 million in professional fees, and $28 million of accrued liabilities related to the Contributed EFH Entities.


•	Payment of $12 million in professional fees.


(9)	Reflects the conversion of the TCEH DIP Roll Facilities of $3.387 billion to the Vistra Operations Credit Facilities at Emergence, the issuance and sale of mandatorily redeemable preferred stock of PrefCo for $70 million, and the obligation related to a corporate office space lease contributed to Vistra Energy pursuant to the Plan of Reorganization. See Note 14 for additional details.


(10)	Reflects the elimination of TCEH's liabilities subject to compromise pursuant to the Plan of Reorganization (see Note 5). Liabilities subject to compromise were settled as follows in accordance with the Plan of Reorganization:



Notes, loans and other debt	$	31,668
Accrued interest on notes, loans and other debt	646
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements	1,243
Trade accounts payable and other expected allowed claims	192
Third-party liabilities subject to compromise	33,749
LSTC from the Contributed EFH Entities	8
Total liabilities subject to compromise	33,757
Fair value of equity issued to TCEH first lien creditors	(7,741		)
TRA Rights issued to TCEH first lien creditors	(574		)
Cash distributed and accruals for TCEH first lien creditors	(377		)
Cash distributed for TCEH unsecured claims	(502		)
Cash distributed and accruals for TCEH administrative claims	(60		)
Settlement of affiliate balances	(99		)
Net liabilities of contributed entities and other items	(60		)
Gain on extinguishment of LSTC	$	24,344


(11)	Reflects the deferred income tax impact of the Plan of Reorganization implementation, including cancellation of debts and adjustment of tax basis of certain assets of PrefCo.


(12)	Reflects the estimated present value of the TRA obligation. See Note 10 for further discussion of the TRA obligation valuation assumptions.


(13)	Primarily reflects the following:


•	Addition of $122 million in liabilities primarily related to benefit plan obligations associated with a pension plan and a health and welfare plan assumed by Vistra Energy pursuant to the Plan of Reorganization. See Note 19 for further discussion of the benefit plan obligations.


•	Payment of $7 million in settlements related to split life insurance costs with a prior affiliate entity.


(14)	Reflects the issuance of approximately 427,500,000 shares of Vistra Energy common stock, par value of $0.01 per share, to the TCEH first lien creditors. See Note 16.


(15)	Reflects adjustments to present Vistra Energy equity value at approximately $7.741 billion based on a reconciliation from the $10.5 billion enterprise value described above under Reorganization Value as depicted below:



Enterprise value	$	10,500
Vistra Operations Credit Facility – Initial Term Loan B Facility	(2,871		)
Vistra Operations Credit Facility – Term Loan C Facility	(655		)
Accrual for post-Emergence claims satisfaction	(181		)
Tax Receivable Agreement obligation	(574		)
Preferred stock of PrefCo	(70		)
Other items	(2		)
Cash and cash equivalents	801
Restricted cash	793
Equity value at Emergence	$	7,741
Common stock at par value	$	4
Additional paid-in capital	7,737
Equity value	$	7,741
Shares outstanding at October 3, 2016 (in millions)	427.5
Per share value	$	18.11


(16)	Membership Interest impact of Plan of Reorganization are shown below:



Gain on extinguishment of LSTC	$	24,344
Elimination of accumulated other comprehensive income	(22		)
Change in control payments	(23		)
Professional fees	(33		)
Other items	(14		)
Pretax gain on reorganization adjustments (Note 5)	24,252
Deferred tax impact of the Plan of Reorganization and Spin-off	576
Total impact to membership interests	$	24,828

Fresh start adjustments


(17)	Reflects the reduction of inventory to fair value, including (1) adjustment of fuel inventory to current market prices, and (2) an adjustment to the fair value of materials and supplies inventory primarily used in our lignite/coal-fueled generation assets and related mining operations.


(18)	Reflects the $12 million increase in the fair value of certain real property assets and $3 million reduction of the fair value for other investments.


(19)	Reflects the change in fair value of property, plant and equipment related primarily to generation and mining assets as detailed below:



Property, Plant and Equipment	Adjustment			Fair Value
Generation plants and mining assets	$	(6,057	)	$	3,698
Land	140			490
Nuclear Fuel	(23		)	157
Other equipment	(30		)	97
Total	$	(5,970	)	$	4,442

We engaged a third-party valuation specialist to assist in preparing the values for our property, plant and equipment. For our generation plants and related mining assets, an income approach was utilized in valuing those assets based on discounted cash flow models that forecast the cash flows of the related assets over their respective useful lives. Significant estimates and assumptions utilized in those models include (1) long-term wholesale power price forecasts, (2) fuel cost forecasts, (3) expected generation volumes based on prevailing forecasts and expected maintenance outages, (4) operations and maintenance costs, (5) capital expenditure forecasts and (6) risk adjusted discount rates based on the cash flows produced by the specific generation asset. The fair value of the generation plants and mining assets is based upon Level 3 inputs utilized in the income approach.

The fair value estimates for land and nuclear fuel utilized the market approach, which included utilizing recent comparable sales information and current market conditions for similarly situated land. Nuclear fuel values were determined by utilizing market pricing information for uranium. The fair value of land and nuclear fuel are based upon Level 3 inputs.

(20)

Reflects the adjustment in fair value of $2.256 billion to identifiable intangible assets, including $1.636 billion increase related to retail customer relationships, $270 million increase related to the retail trade name, $190 million increase related to an electricity supply contract, $164 million increase related to retail and wholesale contracts and $4 million decrease related to other intangible assets (see Note 8).

Also reflects the reduction of fair value of $476 million to identifiable intangible liabilities, including a reduction of $525 million related to an electricity supply contract and an increase of $49 million to wholesale contracts.


(21)	Reflects the deferred income tax impact of fresh-start adjustments to property, plant, and equipment, inventory, intangibles and debt issuance costs.


(22)	Primarily reflects the following:

•

Addition of $197 million regulatory asset related to the deficiency of the nuclear decommissioning trust investment as compared to the nuclear generation plant retirement obligation. Pursuant to Texas regulatory provisions, the trust fund for decommissioning our nuclear generation facility is funded by a fee surcharge billed to REPs by Oncor, as a collection agent, and remitted monthly to Vistra Energy.


•	Adjustment to remove $26 million of unamortized debt issuance costs to reflect the Vistra Operations Credit Facilities at fair market value.


(23)	Reflects the increase in fair value of the Vistra Operations Credit Facilities in the amount of $151 million based on the quoted market prices of the facilities.


(24)	Increase in fair value of asset retirement obligation related to the plant retirement, mining and reclamation retirement, and coal combustion residuals. See Note 23 for further discussion of our asset retirement obligations.


(25)	Reflects the following:


•	Reduction in fair value of unfavorable contracts related to wholesale contracts and a portion of an electricity supply contract in the amount of $476 million. See footnote (20) above for further detail.


•	Reduction of $465 million related to reduction in liability that represented excess amounts in the nuclear decommissioning trust above the carrying value of the asset retirement obligation related to our nuclear generation plant decommissioning.


•	Increase in fair value of obligations related to leased property in the amount of $29 million.


•	Increase in fair value of Pension and OPEB obligations in the amount of $12 million.


(26)	Reflects the extinguishment of Predecessor membership interest and accumulated other comprehensive loss per the Plan of Reorganization.


(27)	Reflects increase in goodwill balance to present final goodwill as the reorganization value in excess of the identifiable tangible assets, intangible assets, and liabilities at Emergence.



Business enterprise value	$	10,500
Add: Fair value of liabilities excluded from enterprise value	3,030
Less: Fair value of tangible assets	(8,215		)
Less: Fair value of identified intangible assets	(3,408		)
Vistra Energy goodwill	$	1,907

Revenue (Notes)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Text Block]

REVENUE

The following tables disaggregate our revenue by major source:



	Year Ended December 31, 2018
	Retail			ERCOT			PJM			NY/NE			MISO			Asset Closure			CAISO/Eliminations			Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	4,426		$	—		$	—		$	—		$	—		$	—		$	—		$	4,426
Retail energy charge in Northeast/Midwest	1,123			—			—			—			—			—			—			1,123
Wholesale generation revenue from ISO/RTO	—			1,151			792			544			420			52			167			3,126
Capacity revenue	—			—			369			240			53			6			30			698
Revenue from other wholesale contracts	—			214			29			42			133			—			6			424
Total revenue from contracts with customers	5,549			1,365			1,190			826			606			58			203			9,797
Other revenues:
Intangible amortization	(26		)	(1		)	2			(9		)	(9		)	—			—			(43		)
Hedging and other revenues (a)	74			(362		)	(62		)	(41		)	(195		)	(31		)	7			(610		)
Affiliate sales	—			1,632			595			41			318			23			(2,609		)	—
Total other revenues	48			1,269			535			(9		)	114			(8		)	(2,602		)	(653		)
Total revenues	$	5,597		$	2,634		$	1,725		$	817		$	720		$	50		$	(2,399	)	$	9,144

____________


(a)	Includes $380 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 22 for unrealized net gains (losses) by segment.

Retail Energy Charges

Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 45 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation.

Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.

As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.

Wholesale Generation Revenue from ISOs/RTOs

Revenue is recognized when volumes are delivered to the ISO or RTO. Revenue is recognized over time using the output method based on kilowatt hours delivered and cash is settled within 10 days of invoicing. Vistra Energy operates as a market participant within ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO and expects to continue to remain under contract with each ISO or RTO indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted for as a single performance obligation.

Capacity Revenue

We provide capacity to customers through participation in capacity auctions held by the ISO or RTO or through bilateral sales. Generation facilities are awarded auction volumes through the ISO or RTO auction and bilateral sales are based on executed contracts with customers. Capacity revenues consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation and demand response capacity available in order to satisfy system integrity and reliability requirements. Capacity revenues are recognized when the performance obligation is satisfied ratably over time in accordance with the contracts as our power generation facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO or RTO against generation facilities if the facility is not available during the capacity period. The penalties are recorded as a reduction to revenue.

Revenue from Other Wholesale Contracts

Other wholesale contracts include other revenue activity with the ISOs or RTOs, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Revenue is recognized when the service is performed. Revenue is recognized over time using the output method based on kilowatt hours delivered or other applicable measurements, and cash settles shortly after invoicing. Vistra Energy operates as a market participant within ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO and expects to continue to remain under contract with each ISO or RTO indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted for as a single performance obligation.

Other Revenues

Some of our contracts for the sale of electricity meet the definition of a derivative under the accounting standards related to derivative instruments. Revenue from derivative contracts is not considered revenue from contracts with customers under the accounting standards related to revenue. Our revenue from the sale of electricity under derivative contracts, including the impact of unrealized gains or losses on those contracts, are reported in the table above as hedging and other revenues. We have classified all sales to affiliates that are eliminated in consolidation as other revenues in the table above.

Contract and Other Customer Acquisition Costs

We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of December 31, 2018 and January 1, 2018 was $38 million and $22 million, respectively. The amortization related to these costs during the year ended December 31, 2018 totaled $10 million, recorded as selling, general and administrative expenses, and $7 million, recorded as a reduction to operating revenues in the statement of consolidated income (loss).

Practical Expedients

The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient. We do not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue.

Performance Obligations

As of December 31, 2018, we have future performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO or RTO or through bilateral sales. Therefore, an obligation exists as of the date of the results of the respective ISO or RTO capacity auction or the contract execution date for bilateral customers. The transaction price is also set by the results of the capacity auction and/or executed contract. These obligations total $968 million, $718 million, $720 million, $342 million and $38 million that will be recognized in the years ending December 31, 2019, 2020, 2021, 2022 and 2023, respectively, and $65 million thereafter. Capacity revenues are recognized as capacity services are provided to the related ISOs or RTOs or bilateral counterparties.

Accounts Receivable

The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts with customers and other activities:



	December 31, 2018
Trade accounts receivable from contracts with customers — net	$	951
Other trade accounts receivable — net	136
Total trade accounts receivable — net	$	1,087

(Goodwill And Identifiable Intangible Assets) (Notes)

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill And Identifiable Intangible Assets

GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

The carrying value of goodwill totaled $2.068 billion and $1.907 billion at December 31, 2018 and 2017, respectively. Of the total goodwill, $161 million arose in connection with the Merger and is recorded at the corporate and other level non-segment operations pending completion of the purchase price allocation in the first quarter of 2019, at which time goodwill will be allocated to reporting units. The remaining $1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to our ERCOT Retail reporting unit. There have been no impairments of Goodwill since Emergence. Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.

Goodwill and intangible assets with indefinite useful lives are required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist. As of the Effective Date, we have selected October 1 as our annual goodwill test date. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our ERCOT Retail reporting unit exceeded its carrying value at October 1, 2018. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition, interest rates and changes in reporting unit book value.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:



	December 31, 2018						December 31, 2017
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	1,680	$	876	$	804	$	1,648	$	572	$	1,076
Software and other technology-related assets	270		105		165		183		47		136
Retail and wholesale contracts	316		138		178		154		87		67
Contractual service agreements	70		—		70		—		—		—
Other identifiable intangible assets (a)	42		15		27		33		11		22
Total identifiable intangible assets subject to amortization	$	2,378	$	1,134	1,244		$	2,018	$	717	1,301
Retail trade names (not subject to amortization)					1,245						1,225
Mineral interests (not currently subject to amortization)					4						4
Total identifiable intangible assets					$	2,493					$	2,530

____________


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

Identifiable intangible liabilities are comprised of the following:



	Year Ended December 31,
	2018		2017
Identifiable Intangible Liability
Contractual service agreements	$	136	$	—
Purchase and sale contracts	195		36
Environmental allowances	$	70	$	—
Total identifiable intangible liabilities	$	401	$	36

Amortization expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the statements of consolidated income (loss)) consisted of:



			Successor						Predecessor
Identifiable Intangible Assets and Liabilities	Statements of Consolidated Income (Loss) Line	Remaining useful lives of identifiable intangible assets at December 31, 2018 (weighted average in years)	Year Ended December 31,				Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Identifiable Intangible Assets and Liabilities	Statements of Consolidated Income (Loss) Line		2018		2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Retail customer relationship	Depreciation and amortization	4	$	304	$	420	$	152	$	9
Software and other technology-related assets	Depreciation and amortization	3	62		38		9		44
Retail and wholesale contracts/purchase and sale contracts	Operating revenues/fuel, purchased power costs and delivery fees	4	43		59		38		—
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	4	58		15		4		6
Total amortization expense (a)			$	467	$	532	$	203	$	59

____________


(a)	Amounts recorded in depreciation and amortization totaled $370 million, $463 million, $162 million and $58 million for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively. Excludes contractual services agreements.

Following is a description of the separately identifiable intangible assets. In connection with fresh start reporting or the Merger (see Notes 2 and 6), the intangible assets were adjusted based on their estimated fair value as of the Effective Date or the Merger Date, based on observable prices or estimates of fair value using valuation models. The purchase price allocation is substantially complete, but is dependent upon final valuation determinations, which may materially change from our current estimates. We currently expect the final purchase price allocation will be completed no later than the first quarter of 2019.

•

Retail customer relationship – Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

•

Retail trade names – Our retail trade name intangible asset represents the fair value of the TXU Energy^TM, 4Change Energy^TM, Homefield and Dynegy Energy Services trade names, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets. Significant assumptions included within the development of the fair value estimate include estimated gross margins for future periods and implied royalty rates. On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2018.

•

Retail and wholesale contracts/purchase and sale contracts – These intangible assets represent the value of various retail and wholesale contracts and purchase and sale contracts. The contracts were identified as either assets or liabilities based on the respective fair values as of the Effective Date or the Merger Date utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The intangible assets or liabilities are being amortized in relation to the economic terms of the related contracts.

•

Contractual service agreements – Our acquired contractual service agreements represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements, rail transportation agreements and rail car leases, and are being amortized based on the expected usage of the service agreements over the contract terms. The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment. Amortization of rail transportation and rail car lease agreements is recorded to fuel, purchased power costs and delivery fees.

Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of December 31, 2018, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2019	$	299
2020	$	201
2021	$	154
2022	$	91
2023	$	67

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Taxes

INCOME TAXES

Successor

Vistra Energy files a United States federal income tax return that includes the results of its consolidated subsidiaries. Vistra Energy is the corporate parent of the Vistra Energy consolidated group. Pursuant to applicable United States 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.

Predecessor

Prior to the Effective Date, EFH Corp. was the corporate parent of the EFH Corp. consolidated group, while TCEH and the Contributed EFH Debtors were classified as disregarded entities for U.S. federal income tax purposes. For the 2016 tax year (through the period until the Effective Date) EFH Corp. filed a U.S. federal income tax return in October 2017 that included the results of TCEH and the EFH Contributed Debtors. Pursuant to applicable U.S. 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 TCEH and the Contributed EFH Debtors) were parties to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate member or disregarded entity in the EFH Corp. group was required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. Pursuant to the Plan of Reorganization, the TCEH Debtors and the Contributed EFH Debtors rejected this agreement on the Effective Date. See Note 5 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.

Income Tax Expense (Benefit)

The components of our income tax expense (benefit) are as follows:



	Successor								Predecessor
	Year Ended December 31,					Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017		Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Current:
U.S. Federal	$	(13	)	$	72	$	—		$	(6	)
State	30			14		6			9
Total current	17			86		6			3
Deferred:
U.S. Federal	(8		)	417		(75		)	(1,234		)
State	(54		)	1		(1		)	(36		)
Total deferred	(62		)	418		(76		)	(1,270		)
Total	$	(45	)	$	504	$	(70	)	$	(1,267	)

Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded:



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Income (loss) before income taxes	$	(101	)	$	250		$	(233	)	$	21,584
US federal statutory rate	21		%	35		%	35		%	35		%
Income taxes at the U.S. federal statutory rate	(20		)	88			(82		)	7,554
Nondeductible TRA accretion	8			(80		)	5			—
State tax, net of federal benefit	22			13			3			(21		)
Impacts of tax reform legislation on deferred taxes	—			451			—			—
Return to provision adjustment	(12		)	19			—			—
Remeasurement of historical Vistra Energy deferred taxes for expanded state footprint	(54		)	—			—			—
Effect of refundable minimum tax credits no longer subject to sequestration	(15		)	—			—			—
Nondeductible compensation	8			—			—			—
Nondeductible transaction costs	3			—			—			—
Equity awards	(3		)	—			—			—
Nondeductible debt restructuring costs	—			—			2			38
Nondeductible interest expense	—			—			—			12
Nontaxable gain on extinguishment of LSTC	—			—			—			(8,593		)
Valuation allowance on state NOLs	20			—			—			(210		)
Other	(2		)	13			2			(47		)
Income tax expense (benefit)	$	(45	)	$	504		$	(70	)	$	(1,267	)
Effective tax rate	44.6		%	201.6		%	30.0		%	(5.9		)%

Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2018 and 2017 are as follows:



	December 31,
	2018		2017
Noncurrent Deferred Income Tax Assets
Tax credit carryforwards	$	76	$	—
Loss carryforwards	958		—
Property, plant and equipment	—		520
Identifiable intangible assets	184		81
Long-term debt	188		20
Employee benefit obligations	109		56
Commodity contracts and interest rate swaps	212		25
Other	40		8
Total deferred tax assets	$	1,767	$	710
Noncurrent Deferred Income Tax Liabilities
Property, plant and equipment	406		—
Total deferred tax liabilities	406		—
Valuation allowance	35		—
Net Deferred Income Tax Asset	$	1,326	$	710

At December 31, 2018, we had total deferred tax assets of approximately $1.326 billion that were substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment, as well as federal and state net operating loss (NOL) carryforwards. Our deferred tax assets were significantly impacted by the Merger. As of December 31, 2018, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income, and thus no valuation allowance was required. We recognized a partial valuation allowance of $20 million on the net operating loss carryforwards related to Illinois due to forecasted expiration. In addition, in our purchase price allocation we recognized a valuation allowance of $15 million for separate state jurisdictions.

At December 31, 2018, we had $3.560 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2032. At December 31, 2018, we had $255 million alternative minimum tax (AMT) credits refundable through the TCJA available.

The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax asset of $2 million at December 31, 2018 and a net deferred tax liability of $6 million at December 31, 2017.

Liability for Uncertain Tax Positions

Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.

We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were immaterial in the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016. The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets, during the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016:



	Successor						Predecessor
	Year Ended December 31,				Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
	2018		2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Balance at beginning of period, excluding interest and penalties	$	—	$	—	$	—	$	36
Additions allocated in the Merger	39		—		—		—
Reductions based on tax positions related to prior years	—		—		—		(1		)
Settlements with taxing authorities	—		—		—		(35		)
Balance at end of period, excluding interest and penalties	$	39	$	—	$	—	$	—

Successor — Vistra Energy and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and are expected to be subject to examinations by the IRS and other taxing authorities. Vistra Energy is not currently under audit by the IRS for any period. Uncertain tax positions totaling $39 million at December 31, 2018 arose in connection with the Merger and our assessment of the assumed liabilities is not complete as discussed in Note 2. We had no uncertain tax positions at December 31, 2017.

Predecessor — EFH Corp. and its subsidiaries file or have filed income tax returns in U.S. Federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. EFH Corp. filed a request for prompt determination of its 2016 tax return with the IRS in October 2017, and such return was accepted for expedited review in December 2017. As a result, the IRS audit of EFH Corp.'s 2016 tax return concluded in April 2018. Texas franchise and margin tax return examinations have been completed.

In September 2016, EFH Corp. entered into a settlement agreement with the Texas Comptroller of Public Accounts (Comptroller) whereby the Comptroller agreed to release all claims and liabilities related to the EFH Corp. consolidated group's state taxes, including sales tax, gross receipts utility tax, franchise tax and direct pay tax, through the agreement date, in exchange for a release of all refund claims and a one-time payment of $12 million. This settlement was entered and approved by the Bankruptcy Court in September 2016. As a result of the settlement, our Predecessor reduced the liability for uncertain tax positions by $27 million.

In July 2016, EFH Corp. executed a Revenue Agent Report (RAR) with the IRS for the 2010 through 2013 tax years. As a result of the RAR, our Predecessor reduced the liability for uncertain tax positions by $1 million, resulting in a reclassification to the accumulated deferred income tax liability. Total cash payment to be assessed by the IRS for tax years 2010 through 2013, but not expected to be paid during the pendency of the Chapter 11 Cases of the EFH Debtors, is approximately $15 million, plus any interest that may be assessed.

In March 2016, EFH Corp. signed a RAR with the IRS for the 2014 tax year. No financial statement impacts resulted from the signing of the 2014 RAR.

Tax Matters Agreement

On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.

Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra Energy is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp.

We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions.

Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off.

Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off.

Tax Receivable Agreement Obligation (Notes)

12 Months Ended

Dec. 31, 2018

Tax Receivables Agreement Obligation [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 our Predecessor. 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 U.S. federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 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 of Reorganization. Such TRA Rights are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 21).

During the year ended December 31, 2018, we recorded an increase to the carrying value of the TRA obligation totaling approximately $14 million as a result of changes in the timing of estimated payments and new multistate tax impacts resulting from the Merger. During the year ended December 31, 2017, we recorded a decrease to the carrying value of the TRA obligation totaling $295 million related to changes in the timing of estimated payments resulting from changes in certain tax assumptions including (a) the impacts of Luminant's plan to retire its Monticello, Sandow 4, Sandow 5 and Big Brown generation plants and the impacts of the Alcoa settlement (see Note 4), (b) investment tax credits we expect to receive related to the Upton 2 solar development project (see Note 3), (c) assets acquired in the Odessa Acquisition (see Note 3) and (d) the impacts of other forecasted tax amounts.

The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016:



	Successor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016
TRA obligation at the beginning of the period	$	357		$	596		$	574
Accretion expense	65			82			22
Payments	(16		)	(26		)	—
Changes in tax assumptions impacting timing of payments	14			(62		)	—
Revaluation due to tax reform legislation	—			(233		)	—
TRA obligation at the end of the period	420			357			596
Less amounts due currently	—			(24		)	—
Noncurrent TRA obligation at the end of the period	$	420		$	333		$	596

As of December 31, 2018, the estimated carrying value of the TRA obligation totaled $420 million, which represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21% for 2018 and 35% for 2017 and 2016, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra Energy now operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of December 31, 2018, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion, with more than half of such amount expected to be attributable to the first 15 tax years following Emergence, and the final payment expected to be made approximately 40 years following Emergence (if the TRA is not terminated earlier pursuant to its terms).

The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation. During the year ended December 31, 2018, the Impacts of Tax Receivable Agreement on the consolidated income (loss) totaled $79 million, which represents the changes to the carrying value of the TRA obligation discussed above and accretion expense totaling $65 million. During the year ended December 31, 2017, the Impacts of Tax Receivable Agreement on the statement of consolidated income (loss) totaled $213 million, which represents the reduction to the carrying value of the TRA obligation discussed above partially offset by accretion expense totaling $82 million. During the period from October 3, 2016 through December 31, 2016, the Impacts of the Tax Receivable Agreement represents accretion expense totaling $22 million.

Interest Expense and Related Charges

12 Months Ended

Dec. 31, 2018

Interest Expense and Related Charges [Abstract]

Interest Expense and Related Charges

INTEREST EXPENSE AND RELATED CHARGES



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Interest paid/accrued post-Emergence	$	537		$	213		$	51		$	—
Interest paid/accrued on debtor-in-possession financing	—			—			—			76
Adequate protection amounts paid/accrued	—			—			—			977
Unrealized mark-to-market net (gains) losses on interest rate swaps	5			(29		)	11			—
Amortization of debt issuance costs, discounts and premiums	—			4			(1		)	4
Debt extinguishment loss	27			—			—			—
Capitalized interest	(12		)	(7		)	(3		)	(9		)
Other	15			12			2			1
Total interest expense and related charges	$	572		$	193		$	60		$	1,049

Successor

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, considering the interest rate swaps discussed in Note 14, was 4.24% and 4.38% at December 31, 2018 and 2017, respectively.

Predecessor

Interest expense for the Predecessor period from January 1, 2016 through October 2, 2016 reflects interest paid and accrued on debtor-in-possession financing (see Note 14) and adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors in exchange for their consent to the senior secured, super-priority liens contained in the DIP Facility. The interest rate applicable to the adequate protection amounts paid/accrued for the Predecessor period from January 1, 2016 through October 2, 2016 was 4.95%.

The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. Other than amounts ordered or approved by the Bankruptcy Court, effective on the Petition Date, our Predecessor discontinued recording interest expense on outstanding pre-petition debt classified as LSTC. The table below shows contractual interest amounts, which are amounts due under the contractual terms of the outstanding debt, including debt subject to compromise during the Chapter 11 Cases. Interest expense reported in our statements of consolidated income (loss) does not include contractual interest on pre-petition debt classified as LSTC totaling $640 million for the Predecessor period from January 1, 2016 through October 2, 2016, which had been stayed by the Bankruptcy Court effective on the Petition Date. Adequate protection amounts paid/accrued presented below excludes interest paid/accrued on TCEH first-lien interest rate and commodity hedge claims totaling $47 million for the Predecessor period from January 1, 2016 through October 2, 2016, as such amounts are not included in contractual interest amounts below.



	Predecessor
	Period from January 1, 2016 through October 2, 2016
Contractual interest on debt classified as LSTC	$	1,570
Adequate protection amounts paid/accrued	930
Contractual interest on debt classified as LSTC not paid/accrued	$	640

Earnings Per Share (Notes)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

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.



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Net loss attributable to common stock — basic (a)	$	(54	)	$	(254	)	$	(163	)
Weighted average shares of common stock outstanding — basic	504,954,371			427,761,460			427,560,620
Net loss per weighted average share of common stock outstanding — basic	$	(0.11	)	$	(0.59	)	$	(0.38	)
Weighted average shares of common stock outstanding — diluted	504,954,371			427,761,460			427,560,620
Net loss per weighted average share of common stock outstanding — diluted	$	(0.11	)	$	(0.59	)	$	(0.38	)


(a)	The minimum settlement amount of tangible equity units, or 15,056,260 shares, are considered to be outstanding and are

included in the computation of basic net income per share (see Note 16).

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 14,165,813, 3,642,844 and 7,332,789 shares for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016, respectively.

Accounts Receivable Securitization Program (Notes)	12 Months Ended
Accounts Receivable Securitization Program (Notes)	Dec. 31, 2018
Accounts Receivable Securitization Program [Abstract]
Accounts Receivable Securitization Program [Text Block]	ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra Energy, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). The Receivables Facility is currently scheduled to terminate in August 2019, unless termination occurs earlier in accordance with the terms of the Receivables Facility. The Receivables Facility provides RecCo with the ability to borrow up to $350 million. Under the Receivables Facility, TXU Energy may sell or contribute, on an ongoing basis and without recourse, its accounts receivable to its special purpose subsidiary, RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may, from time to time, sell an undivided interest in all the receivables to the Purchasers, and its assets and credit are not available to satisfy the debts and obligations of any person, including affiliates of RecCo. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our statements of consolidated cash flows. Receivables transferred to the Purchasers remain on Vistra Energy's balance sheet and Vistra Energy reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the trade receivables on behalf of RecCo and the Purchasers, as applicable. As of December 31, 2018, the receivables facility totaled $339 million and is supported by $477 million of RecCo gross receivables.

Long-Term Debt

12 Months Ended

Dec. 31, 2018

Debtor-In-Possession Obligations [Abstract]

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.



	December 31,
	2018			2017
Vistra Operations Credit Facilities	$	5,813		$	4,311
Vistra Operations 5.500% Senior Notes, due September 1, 2026	1,000			—
Vistra Energy Senior Notes:
7.375% Senior Notes, due November 1, 2022	1,707			—
5.875% Senior Notes, due June 1, 2023	500			—
7.625% Senior Notes, due November 1, 2024	1,147			—
8.034% Senior Notes, due February 2, 2024	25			—
8.000% Senior Notes, due January 15, 2025	81			—
8.125% Senior Notes, due January 30, 2026	166			—
Total Vistra Energy Senior Notes	3,626			—
Other:
7.000% Amortizing Notes, due July 1, 2019	24			—
Forward Capacity Agreements	236			—
Equipment Financing Agreements	120			—
Mandatorily redeemable subsidiary preferred stock (a)	70			70
8.82% Building Financing due semiannually through February 11, 2022 (b)	21			27
Total other long-term debt	471			97
Unamortized debt premiums, discounts and issuance costs (c)	155			15
Total long-term debt including amounts due currently	11,065			4,423
Less amounts due currently	(191		)	(44		)
Total long-term debt less amounts due currently	$	10,874		$	4,379

____________


(a)	Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note 5). This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance.


(b)	Obligation related to a corporate office space capital lease transferred to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our consolidated balance sheets.


(c)	Includes impact of recording debt assumed in the Merger at fair value.

Vistra Operations Credit Facilities

At December 31, 2018, the Vistra Operations Credit Facilities consisted of up to $8.313 billion in senior secured, first lien revolving credit commitments and outstanding term loans, consisting of revolving credit commitments of up to $2.5 billion, including a $2.3 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $2.793 billion (Term Loan B-1 Facility), $980 million (Term Loan B-2 Facility) and $2.040 billion (Term Loan B-3 Facility, and together with the Term Loan B-1 Facility and the Term Loan B-2 Facility, the Term Loan B Facility).

These amounts reflect an amendment to the Vistra Operations Credit Facilities in June 2018 whereby we incurred $2.050 billion of borrowings under the new Term Loan B-3 Facility and obtained $1.640 billion of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by $1.585 billion. The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. As discussed below, the proceeds from the Term Loan B-3 Facility were used to repay borrowings under the credit agreement that Vistra Energy assumed from Dynegy in connection with the Merger. Additionally, letter of credit term loans totaling $500 million (Term Loan C Facility) were repaid using $500 million of cash from collateral accounts used to backstop letters of credit. Fees and expenses related to the amendment to the Vistra Operations Credit Facilities totaled $42 million in the year ended December 31, 2018, of which $23 million was recorded as interest expense and other charges on the statements of consolidated income (loss), $9 million was capitalized as a reduction in the carrying amount of the debt and $10 million was capitalized as a noncurrent asset.

The Vistra Operations Credit Facilities and related available capacity at December 31, 2018 are presented below.



		December 31, 2018
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity
Revolving Credit Facility (a)	June 14, 2023	$	2,500	$	—	$	1,135
Term Loan B-1 Facility	August 4, 2023	2,793		2,793		—
Term Loan B-2 Facility	December 14, 2023	980		980		—
Term Loan B-3 Facility	December 31, 2025	2,040		2,040		—
Total Vistra Operations Credit Facilities		$	8,313	$	5,813	$	1,135

___________


(a)	Facility to be used for general corporate purposes. Facility includes a $2.3 billion letter of credit sub-facility, of which $1.365 billion of letters of credit were outstanding at December 31, 2018 and which reduce our available capacity.

In February and June 2018, certain pricing terms for the Vistra Operations Credit Facilities were amended. We accounted for these transactions as modifications of debt. At December 31, 2018, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan B-1, B-2 and B-3 Facilities bear interest based on applicable LIBOR rates plus fixed spreads of 2.00%, 2.25% and 2.00%, respectively. At December 31, 2018, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 4.52%, 4.77% and 4.47% under the Term Loan B-1, B-2 and B-3 Facilities, respectively. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payable with respect to any unused portion of the available Revolving Credit Facility.

Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of the Vistra Operations Credit Facilities.

The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forth in the Vistra Operations Credit Facilities.

The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. As of December 31, 2018, we were in compliance with this financial covenant. 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 — Effective January 2017, we entered into $3.0 billion notional amount of interest rate swaps to hedge a portion of our exposure to our variable rate debt. The interest rate swaps expire in July 2023. In May and June 2018, we entered into $3.0 billion notional amount of interest rate swaps that become effective in July 2023 and expire in July 2026.

In June 2018, we completed the novation of $1.959 billion of Vistra Energy (legacy Dynegy) interest rate swaps to Vistra Operations. In June 2018, $238 million of these interest rate swaps expired. The remaining interest rate swaps expire between March 2019 and February 2024.

The interest rate swaps effectively fix the interest rates between 4.13% and 4.38% on $4.717 billion of our variable rate debt. The interest rate swaps that become effective in July 2023 and expire in July 2026 effectively fix the interest rates between 4.97% and 5.04% on $3.0 billion of our variable rate debt during the period. The interest rate swaps are secured by a first lien secured interest on a pari passu basis with the Vistra Operations Credit Facilities.

Alternative Letter of Credit Facility

In December 2018, we entered into an alternative letter of credit facility with a facility limit of approximately $193 million at February 25, 2019. The facility became effective in January 2019.

Vistra Energy (legacy Dynegy) Credit Agreement

On the Merger Date, Vistra Energy assumed the obligations under Dynegy's $3.563 billion credit agreement consisting of a $2.018 billion senior secured term loan facility due 2024 and a $1.545 billion senior secured revolving credit facility. As of the Merger Date, there were no cash borrowings and $656 million of letters of credit outstanding under the senior secured revolving credit facility. On April 23, 2018, $70 million of the senior secured revolving credit facility matured. In June 2018, the $2.018 billion senior secured term loan facility due 2024 was repaid using proceeds from the Term Loan B-3 Facility. In addition, all letters of credit outstanding under the senior secured revolving credit facility were replaced with letters of credit under the amended Vistra Operations Credit Facilities discussed above, and the revolving credit facility assumed from Dynegy in connection with the Merger was paid off in full and terminated.

Vistra Operations Senior Notes

In February 2019, Vistra Operations issued and sold $1.3 billion aggregate principal amount of 5.625% senior notes due 2027 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act of 1933, as amended (the 2019 Notes Offering). The senior notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and J.P. Morgan Securities LLC, as representative of the several initial purchasers. Net proceeds from the 2019 Notes Offering totaling approximately $1.287 billion, together with cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with (i) the 2019 Tender Offer described below, (ii) the redemption of approximately $35 million aggregate principal amount of our 7.375% senior notes due 2022 and (iii) the redemption of approximately $25 million aggregate principal amount of our outstanding 8.034% senior notes due 2024. The 5.625% senior notes mature in February 2027, with interest payable in cash semiannually in arrears on February 15 and August 15 beginning August 15, 2019.

In August 2018, Vistra Operations issued $1.0 billion principal amount of 5.50% senior notes due 2026 in an offering to eligible purchasers. The senior notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers. Fees and expenses related to the offering totaled $12 million in the three months ended September 30, 2018, which was capitalized as a reduction in the carrying amount of the debt. Net proceeds from the sale of the senior notes totaling approximately $990 million, together with cash on hand and cash received from the funding of the Receivables Facility (see Note 13), were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the August 2018 cash tender offers described below. The 5.500% senior notes mature in September 2026, with interest payable in cash semiannually in arrears on March 1 and September 1 beginning March 1, 2019.

The indenture governing the 5.500% senior notes provides for the full and unconditional guarantee by certain direct and indirect subsidiaries of Vistra Operations of the punctual payment of the principal and interest on the notes. The Indenture contains certain covenants and restrictions, including, among others, restrictions on the ability of the Issuer and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

Vistra Energy Senior Notes

Bond Repurchase Program — In November 2018, our board of directors (the Board) authorized a bond repurchase program under which up to $200 million principal amount of outstanding Vistra Energy senior notes could be repurchased. Through December 31, 2018, $119 million principal amount of senior notes had been repurchased. Fees and expenses related to the repurchases totaled $7 million in the three months ended December 31, 2018 and were recorded as interest expense and other charges on the statements of consolidated income (loss).

2019 Tender Offer and Consent Solicitation — In February 2019, Vistra Energy used the net proceeds from the issuance of the Vistra Operations 5.625% senior notes due 2027 to fund a cash tender offer (the 2019 Tender Offer) to purchase for cash $1.193 billion aggregate principal amount of 7.375% senior notes due 2022 assumed in the Merger.

In connection with the 2019 Tender Offer, Vistra Energy also commenced solicitation of consents from holders of the 7.375% senior notes due 2022. Vistra Energy received the requisite consents from the holders of the 7.375% senior notes due 2022 and amended the indenture governing these senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default.

August 2018 Tender Offers and Consent Solicitations — In August 2018, Vistra Energy used the net proceeds from the issuance of the Vistra Operations 5.500% senior notes due 2026, proceeds from the Receivables Facility (see Note 13) and cash on hand to fund cash tender offers (the 2018 Tender Offers) to purchase for cash $1.542 billion of senior notes assumed in the Merger. We recorded an extinguishment loss of $27 million on the transactions in the year ended December 31, 2018. Notes purchased consisted of the following:


•	$26 million of 7.625% senior notes due 2024;


•	$163 million of 8.034% senior notes due 2024;


•	$669 million of 8.000% senior notes due 2025, and


•	$684 million of 8.125% senior notes due 2026.

In connection with the 2018 Tender Offers, Vistra Energy also commenced solicitations of consents from holders of the 7.375% senior notes due 2022, the 7.625% senior notes due 2024, the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes due 2026 to amend certain provisions of the applicable indentures governing each series of senior notes and the registration rights agreement with respect to the 8.125% senior notes due 2026. Vistra Energy received the requisite consents from the holders of the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes due 2026 (collectively, the Consent Senior Notes) and amended (a) the indentures governing each series of the applicable senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default and (b) the registration rights agreement with respect to the 8.125% senior notes due 2026 to remove, among other things, the requirement that Vistra Energy commence an exchange offer to issue registered securities in exchange for the existing, nonregistered notes.

Assumption of Senior Notes in Merger — On the Merger Date, Vistra Energy assumed $6.138 billion principal amount of Dynegy's senior notes. In May 2018, $850 million of outstanding 6.75% senior notes due 2019 were redeemed at a redemption price of 101.688% of the aggregate principal amount, plus accrued and unpaid interest to but not including the date of redemption. Fees and expenses related to the redemption totaled $14 million in the three months ended June 30, 2018 and were recorded as interest expense and other charges on the statements of consolidated income (loss). In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities (and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding.

The senior notes that remain outstanding after the closing of the Tender Offers are unsecured and unsubordinated obligations of Vistra Energy and are guaranteed by substantially all of its current and future wholly owned domestic subsidiaries that from time to time are a borrower or guarantor under the agreement governing the Vistra Operations Credit Facilities (Credit Facilities Agreement) (see Note 24). The respective indentures of the senior notes (except with respect to the Consent Senior Notes) limit, among other things, the ability of the Company or any of the guarantors to create liens upon any principal property to secure debt for borrowed money in excess of, among other limitations, 30% of total assets. The respective indentures of the senior notes also contain customary events of default which would permit the holders of the applicable series of senior notes to declare such notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely principal or interest payments on such notes or (except with respect to the Consent Senior Notes) other indebtedness aggregating $100 million or more, and, except with respect to the Consent Senior Notes, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.

Amortizing Notes

On the Merger Date, Vistra Energy assumed the obligations of Dynegy's senior amortizing note (Amortizing Notes) maturing on July 1, 2019. The Amortizing Notes were issued in connection with the issuance of the tangible equity units (TEUs) by Dynegy (see Note 16). Each installment payment per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00%. Interest will be calculated on the basis of a 360-day year consisting of twelve 30-day months. Payments will be applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the indenture.

The indenture for the Amortizing Notes limits, among other things, the ability of the Company to consolidate, merge, sell, or dispose all or substantially all of its assets. If a fundamental change occurs, or if the Company elects to settle the prepaid stock purchase contracts early, then the holders of the Amortizing Notes will have the right to require the Company to repurchase the Amortizing Notes at a repurchase price equal to the principal amount of the Amortizing Notes as of the repurchase date (as described in the supplemental indenture) plus accrued and unpaid interest. The indenture also contains customary events of default which would permit the holders of the Amortizing Notes to declare those Amortizing Notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely installment payments on the Amortizing Notes or other material indebtedness aggregating $100 million or more, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.

Forward Capacity Agreements

On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a financial institution (Forward Capacity Agreements). The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2018-2019, 2019-2020 and 2020-2021 in the amounts of $5 million, $121 million and $110 million, respectively. We will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as long-term debt of $236 million with an implied interest rate of 4.00%.

Equipment Financing Agreements

On the Merger Date, the Company assumed Dynegy's Equipment Financing Agreements. Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2019 to 2026. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our statements of consolidated cash flows.

Maturities — Long-term debt maturities at December 31, 2018 are as follows:



	December 31, 2018
2019	$	191
2020	205
2021	129
2022	1,782
2023	4,150
Thereafter	4,453
Unamortized premiums, discounts and debt issuance costs	155
Total long-term debt, including amounts due currently	$	11,065

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 totaled $3.465 billion and were used to repay $2.65 billion outstanding borrowings under the former DIP Facility, fund a $650 million collateral account used to backstop issuances of letters of credit and pay $107 million of issuance costs. The remaining balance was used for general corporate purposes. Additionally, $800 million of cash from collateral accounts under the former DIP Facility that was used to backstop letters of credit was released to the Predecessor to be 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

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2018, we had contractual commitments under long-term service and maintenance contracts, energy-related contracts, leases and other agreements as follows.



	Long-Term Service and Maintenance Contracts		Coal purchase and transportation agreements		Pipeline transportation and storage reservation fees		Nuclear Fuel Contracts		Other Contracts
2019	$	175	$	765	$	101	$	69	$	101
2020	181		227		95		71		74
2021	135		118		72		58		20
2022	183		103		48		38		13
2023	133		64		35		46		9
Thereafter	2,619		186		145		155		68
Total	$	3,426	$	1,463	$	496	$	437	$	285

The table above excludes TRA and pension and OPEB plan obligations due to the uncertainty in the timing of those payments.

Expenditures under our coal purchase and coal transportation agreements totaled $955 million, $416 million, $109 million and $139 million for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.

At December 31, 2018, future minimum lease payments under operating leases are as follows:



	Operating Leases (a)
2019	$	35
2020	29
2021	25
2022	20
2023	19
Thereafter	168
Total future minimum lease payments	$	296

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(a)	Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.

Rent reported as operating costs, fuel costs and SG&A expenses totaled $74 million, $69 million, $20 million and $39 million for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.

Guarantees

We have entered into contracts, including the assumed Dynegy senior notes described above, that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2018, 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 December 31, 2018, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $1.365 billion as follows:


•	$1.185 billion 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 ISOs or RTOs;


•	$53 million to support executory contracts and insurance agreements;


•	$55 million to support our REP financial requirements with the PUCT, and


•	$72 million for other credit support requirements.

Surety Bonds

At December 31, 2018, we had outstanding surety bonds totaling $31 million to support performance under various contracts and legal obligations in the normal course of business.

Litigation

Gas Index Pricing Litigation — We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri and Wisconsin) during the relevant time period and seek damages under the respective state antitrust statutes. Four of the cases are putative class actions and one case, Reorganized FLI (nka J.P. Morgan Trust Co., National Assn.) v. Oneok Inc., et al., is an individual action on behalf of Farmland Industries, Inc. (Farmland), with Farmland seeking full consideration damages (i.e., the full amount it paid for natural gas purchases during the relevant timeframe). The cases are consolidated in a multi-district litigation proceeding pending in the U. S. District Court for Nevada. In March 2017, the court denied the class plaintiffs' motions to certify class actions in each of the states, which decision was taken on an interlocutory appeal to U.S Court of Appeals for the Ninth Circuit (Ninth Circuit Court). In August 2018, the Ninth Circuit Court vacated the district court orders denying class certification and remanded the cases to the district court for further consideration of the class certification issue. In September 2018, the defendants filed a joint motion for entry of an order denying class certification, and the plaintiffs filed a motion for remand of the cases to the transferor courts to decide class certification issues. In January 2019, the judge issued an order remanding the consolidated cases in the multi-district proceedings back to their respective courts of origin. Along with the other defendants, we had previously reached settlement terms in the Kansas and Missouri cases, and plaintiffs in those cases filed a Notice of Settlement with the judge in the multi-district court proceeding. As for the Farmland matter, in March 2018, the Ninth Circuit Court reversed a summary judgment in favor of the defendants and it shortly will be remanded for further discovery and other pretrial proceedings. While we cannot predict the outcome of these legal proceedings, or estimate a range of costs, they could have a material impact on our results of operations, liquidity or financial condition.

Advatech Dispute — In September 2016, Illinois Power Generating Company (Genco), terminated its Second Amended and Restated Newton Flue Gas Desulfurization System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014 with Advatech, LLC (Advatech). Advatech issued Genco its final invoice in September 2016 totaling $81 million. Genco contested the invoice in October 2016 and believes the proper amount is less than $1 million. In October 2016, Advatech initiated the dispute resolution process under the contract and filed for arbitration in March 2017. Settlement discussions required under the dispute resolution process were unsuccessful. The arbitration hearing occurred in October 2018, and the arbitration panel has not yet issued an award. We dispute the allegations. While we cannot predict the outcome of this legal proceeding, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

Wood River Rail Dispute — In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's suspension of its Wood River Rail Transportation Agreement with the railroads. Settlement discussions required under the dispute resolution process have been unsuccessful. In March 2018, BNSF Railway Company and Norfolk Southern Railway Company filed a demand for arbitration. The arbitration hearing on the merits is schedule for February 2020. We dispute the railroads' allegations and will defend our position vigorously. While we cannot predict the outcome of this legal proceeding, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

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, including rules for existing facilities that would establish state-specific emissions rate goals to reduce nationwide CO₂ emissions. Various parties (including Luminant) filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) and subsequently, in January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the U.S. 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 was heard in September 2016 before the entire D.C. Circuit Court, but the D.C. Circuit Court has not issued a decision and the case remains in abeyance due to the EPA's decision to review the Clean Power Plan.

In October 2017, the EPA issued a proposed rule that would repeal the Clean Power Plan, with the proposed repeal focusing on what the EPA believes to be the unlawful nature of the Clean Power Plan and asking for public comment on the EPA's interpretations of its authority under the Clean Air Act. In December 2017, the EPA published an advance notice of proposed rulemaking (ANPR) soliciting information from the public as the EPA considers proposing a future rule. Vistra Energy submitted comments on the ANPR in February 2018. Vistra Energy submitted comments on the proposed repeal in April 2018. In August 2018, the EPA published a proposed replacement rule called the Affordable Clean Energy rule. We submitted comments on the proposed Affordable Clean Energy rule in October 2018. In December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units with comments due in March 2019. 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.

Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas

In January 2016, the EPA issued a final rule approving in part and disapproving in part Texas's 2009 State Implementation Plan (SIP) as it relates to the reasonable progress component of the Regional Haze Program and issuing a Federal Implementation Plan (FIP). The EPA's emission limits in the FIP assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity generation units (including Big Brown Units 1 and 2, Monticello Units 1 and 2 and Coleto Creek) and upgrades to existing scrubbers at seven generation units (including Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4).

In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the FIP's Texas requirements. In July 2016, the Fifth Circuit Court granted motions to stay the rule filed by Luminant and the other parties pending final review of the petitions for review. 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. In March 2017, the Fifth Circuit Court remanded the rule back to the EPA for reconsideration. The stay of the rule (and the emission control requirements) remains in effect, and the EPA is required to file status reports of its reconsideration every 60 days. The retirements of our Monticello, Big Brown and Sandow 4 plants should have a favorable impact on this rulemaking and litigation. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

In September 2017, the EPA signed a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas's 2009 SIP and a partial FIP. For SO₂, the rule creates an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating units (including our Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program started on January 1, 2019, and the identified units receive an annual allowance allocation that is equal to their most recent annual CSAPR SO₂ allocation. Cumulatively, our units covered by the program are allocated 100,279 allowances annually. Under the rule, a unit that is listed that does not operate for two consecutive years starting after 2018 would no longer receive allowances after the fifth year of non-operation. We believe the retirements of our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO₂. For NO_X, the rule adopts the CSAPR's ozone program as BART and for particulate matter, the rule approves Texas's SIP that determines that no electricity generation units are subject to BART for particulate matter. The National Parks Conservation Association, the Sierra Club and the Environmental Defense Fund filed a petition challenging the rule in the Fifth Circuit Court as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA in the Fifth Circuit Court action. In March 2018, the Fifth Circuit Court granted a joint motion filed by the EPA and the environmental groups involved to abate the Fifth Circuit Court proceedings until the EPA has taken action on the reconsideration petition and concludes the reconsideration process. In August 2018, the EPA issued a proposed rule affirming the prior BART final rule and seeking comments on that proposal, which were due in October 2018. While we cannot predict the outcome of the rulemaking and legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material impact on our results of operations, liquidity or financial condition.

Affirmative Defenses During Malfunctions

In February 2013, the EPA proposed a rule requiring certain states to remove SIP exemptions for excess emissions during malfunctions or replace them with an affirmative defense. In May 2015, the EPA finalized its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The final rule impacted 36 states, including Texas, Illinois and Ohio, in which we operate. The EPA's final rule would require covered states to remove or replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. Several states (including the State of Texas and the State of Ohio) and various industry parties (including Luminant) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court. Before the oral argument was held, in April 2017, the D.C. Circuit 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 D.C. Circuit Court on the EPA's review of the action at 90-day intervals. In October 2018, the EPA partially granted Texas' petition for reconsideration of the Texas SIP call. 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 could have a material impact on our results of operations, liquidity or financial condition.

SO₂ Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for reconsideration to the EPA. In addition, with respect to Monticello and Big Brown, the retirement of those plants should favorably impact our legal challenge to the nonattainment designations in that the nonattainment designations for Freestone County and Titus County are based solely on the Sierra Club modeling, which we dispute, of SO₂ emissions from Monticello and Big Brown. Regardless, considering these retirements, the nonattainment designations for those counties are no longer supported. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

Effluent Limitation Guidelines (ELGs)

In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, flue desulfurization, fly ash, bottom ash and flue gas mercury control. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG final rule issued in 2015 and administratively stayed the ELG rule's compliance date deadlines pending ongoing judicial review of the rule. The legal challenges pertaining to bottom ash transport water, flue gas desulfurization wastewater and gasification wastewater have been suspended while the EPA reconsiders the rules.

The EPA issued a final rule in September 2017 postponing the earliest compliance dates in the ELG rule for bottom ash transport water and flue-gas desulfurization wastewater by two years, from November 1, 2018 to November 1, 2020.

Given the EPA's decision to reconsider the bottom ash transport water and flue gas desulfurization wastewater provisions of the ELG rule, the rule postponing the ELG rule's earliest compliance dates for those provisions, and the intertwined relationship of the ELG rule with the Coal Combustion Residuals rule discussed below, which is also being reconsidered by the EPA, as well as pending legal challenges concerning both rules, substantial uncertainty exists regarding our projected capital expenditures for ELG compliance, including the timing of such expenditures. While we cannot predict the outcome of this matter, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

New Source Review and CAA Matters

New Source Review — Since 1999, the EPA has engaged in a nationwide enforcement initiative to determine whether coal-fueled power plants failed to comply with the requirements of the New Source Review (NSR) and New Source Performance Standard provisions under the CAA when the plants implemented changes. The EPA's NSR initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

In August 2013, the U.S. Department of Justice (DOJ), 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 NSR standards, at our Big Brown and Martin Lake generation facilities. The lawsuit requests (i) 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 (ii) injunctive relief, including an order to apply for pre-construction permits which may require the installation of best available control technology at the affected units. 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 January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in Luminant's favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the Fifth Circuit Court. After the parties filed their respective briefs in the Fifth Circuit Court, the appeal was argued before the Fifth Circuit Court in March 2018. In October 2018, the Fifth Circuit Court affirmed in part, reversed in part, and remanded to the district court. The Fifth Circuit Court's decision held that the district court properly dismissed all of the civil penalties as time-barred. The Fifth Circuit Court further held that the grounds cited by the district court did not support dismissal of the injunctive relief claims at this early stage of the case and remanded the case back to the district court for further consideration. In November 2018, we filed a petition for rehearing en banc on two issues and the EPA's response to that petition is due in February 2019. We believe that we have complied with all requirements of the CAA and intend to continue to vigorously defend against the remaining allegations. An adverse outcome could require substantial capital expenditures that cannot be determined at this time or retirement of the remaining plant at issue, Martin Lake. The retirement of the Big Brown plant should have a favorable impact on this litigation. We cannot predict the outcome of these proceedings, including the financial effects, if any.

Zimmer NOVs — In December 2014, the EPA issued a notice of violation (NOV) alleging violation of opacity standards at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio State Implementation Plan and the station's air permits including standards applicable to opacity, sulfur dioxide, sulfuric acid mist and heat input. The NOVs remain unresolved. We are unable to predict the outcome of these matters.

Edwards CAA Citizen Suit — In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our MISO segment's Edwards facility. In August 2016, the district court granted the plaintiffs’ motion for summary judgment on certain liability issues. We filed a motion seeking interlocutory appeal of the court's summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The parties completed briefing on motions for summary judgment on remedy issues in October 2018. In January 2019, the court canceled the bench trial scheduled for March 2019 and denied the parties' motions for summary judgment on remedy issues. In February 2019, the court issued an order that anticipates a trial date at the end of September 2019. We dispute the allegations and will defend the case vigorously. We are unable to predict the outcome of these matters.

Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties, or could result in an order or a decision to retire these plants. While we cannot predict the outcome of these legal proceedings, or estimate a range of costs, they could have a material impact on our results of operations, liquidity or financial condition.

Coal Combustion Residuals/Groundwater

In July 2018, the EPA published a final rule that amends certain provisions of the Coal Combustion Residuals (CCR) rule that the agency issued in 2015. The 2018 revisions extend closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. The 2018 revisions also (1) establish groundwater protection standards for cobalt, lithium, molybdenum and lead (2) allow authorized state programs to waive groundwater monitoring requirements when there is a demonstration of no potential for contaminant migration, and (3) allow the permitting authority to issue certifications in lieu of a qualified professional engineer. The 2018 revisions became effective in August 2018, and we are continuing to evaluate the impact on our CCR facilities. Also, on August 21, 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule. The EPA is expected to undertake further revisions to its CCR regulations in response to the D.C. Circuit Court's ruling. In October 2018, the rule that extends certain closure deadlines to 2020 was challenged in the D.C. Circuit Court. In December 2018, the EPA and petitioners filed cross-motions, with the EPA seeking remand without vacatur and petitioners seeking a partial stay or vacatur of the rule. We have intervened in the litigation and filed a motion in support of the EPA. Briefing on the cross-motions is ongoing. While we cannot predict the impacts of these rule revisions (including whether and if so how the states in which we operate will utilize the authority delegated to the states through the revisions), or estimate a range of reasonably possible costs related to these revisions, the changes that result from these revisions could have a material impact on our results of operations, liquidity or financial condition.

MISO Segment — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. In 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of those closure plans.

At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the August 2018 court decision, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, with revised plans submitted in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. By letter dated January 31, 2018, Prairie Rivers Network provided 60-day notice of its intent to sue our subsidiary Dynegy Midwest Generation, LLC under the federal Clean Water Act for alleged unauthorized discharges from the surface impoundments at our Vermilion facility and alleged related violations of the facility's National Pollutant Discharge Elimination System permit. Prairie Rivers Network filed a citizen suit in May 2018, alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. Plaintiffs have appealed the judgment to the U.S Court of Appeals for the Ninth Circuit. We dispute the allegations and will vigorously defend our position.

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility.

In December 2018, the Sierra Club filed a complaint with the IPCB alleging the disposal and storage of coal ash at the Coffeen, Edwards and Joppa generation facilities are causing exceedances of the applicable groundwater standards. We dispute the allegations and will vigorously defend our position.

If remediation measures concerning groundwater are necessary at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time, in part because of the revisions to the CCR rule that the EPA published in July 2018 and the D.C. Circuit Court's vacatur and remand of certain provisions of the EPA's 2015 CCR rule, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs, as determined by our operations and environmental services teams, are reflected in our AROs.

MISO 2015-2016 Planning Resource Auction

In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy could have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint.

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC's Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules, and regulations occurred before or during the PRA (the Order). The Order noted that the investigation is ongoing, and that the conversion of the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Vistra Energy is participating in the investigation on behalf of Dynegy following the closing of the Merger. We believe that our conduct was proper and will defend our position vigorously, but we cannot predict the outcome of the investigation or the amount, if any, of loss that may result. While we cannot predict the outcome of this matter, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. The order did not address the arguments of the complainants regarding the 2015-2016 PRA and stated that those issues remain under consideration and will be addressed in a future order.

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.

Labor Contracts

We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by collective bargaining agreements. The terms of all collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal- and nuclear-fueled generation operations and some of our natural gas-fueled generation operations expire on various dates between March 2019 and March 2022, but remain effective from year-to-year thereafter unless and until terminated by either party. While we cannot predict the outcome of labor contract negotiations, we do not expect any changes in collective bargaining agreements to have a material adverse effect on our results of operations, liquidity or financial condition.

Nuclear Insurance

Nuclear insurance includes nuclear liability coverage, property damage, decontamination and accidental premature decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition.

With regard to liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $14.1 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the United States Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $14.1 billion limit for a single incident. As required, we insure against a possible nuclear incident at our Comanche Peak facility resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).

Under the SFP, in the event of any single nuclear liability loss in excess of $450 million at any nuclear generation facility in the United States, each operating licensed reactor in the United States is subject to an annual assessment of up to $137.6 million. This approximately $137.6 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur in September 2023. Assessments are currently limited to $20.5 million per operating licensed reactor per year per incident. As of December 31, 2018, our maximum potential assessment under the industry retrospective plan would be approximately $275 million per incident but no more than $41 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $450 million per accident at any nuclear facility.

The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $1.06 billion of nuclear decontamination and property damage insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear decontamination and property damage insurance for our Comanche Peak facility in the amount of $2.25 billion and non-nuclear related property damage in the amount of $1.5 billion (subject to a $5 million deductible per accident except for natural hazards which are subject to a $9.5 million deductible per accident), above which we are self-insured.

We also maintain Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at our Comanche Peak facility are out of service for more than twelve weeks as a result of covered direct physical damage. Such coverage provides for weekly payments per unit up to $4.5 million for the first 52 weeks and up to $3.6 million for the remaining 71 weeks. The total maximum coverage is $328 million for non-nuclear property damage and $490 million for nuclear property damage. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.

Equity

12 Months Ended

Dec. 31, 2018

Stockholders' Equity Note [Abstract]

Equity

EQUITY

Successor Shareholders' Equity

Equity Issuances and Repurchases — Changes in the number of shares of common stock outstanding for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 are reflected in the table below.



	Successor
	Year Ended December 31, 2018		Year Ended December 31, 2017	Period from October 3, 2016 through December 31, 2016
Shares outstanding at beginning of period	428,398,802		427,580,232	—
Shares issued (a)	97,639,105		818,570	427,580,232
Shares retired	(6,815	)	—	—
Shares repurchased (b)	(32,815,783	)	—	—
Shares outstanding at end of period	493,215,309		428,398,802	427,580,232

____________


(a)	Includes share awards granted to nonemployee directors. The year ended December 31, 2018 includes 94,409,573 shares issued in connection with the Merger (see Note 2).


(b)	Treasury shares totaled 32,815,783 shares at December 31, 2018, all of which were acquired during the year ended December 31, 2018 in connection with the share repurchase program described below.

Share Repurchase Program — In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of our outstanding common stock could be repurchased. Repurchases under this program were completed on October 19, 2018. On a cumulative basis, 21,421,925 shares of our common stock were repurchased for $500 million (including related fees and expenses) at an average price per share of common stock of $23.36.

In November 2018, we announced that the Board had authorized an incremental share repurchase program (Program) under which up to $1.250 billion of our outstanding stock may be purchased. Through December 31, 2018, 12,073,091 shares of our common stock had been repurchased for $278 million (including related fees and expenses) at an average price per share of common stock of $22.99. At December 31, 2018, $972 million was available for additional repurchases under the Program, and we intend to implement the Program opportunistically from time to time through the end of 2019.

Shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Securities Exchange Act of 1934, as amended, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Program will be determined at our discretion and will depend on a number of factors, including the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the Tax Matters Agreement.

Dividends — Vistra Energy did not declare or pay any dividends during the years ended December 31, 2018 and 2017. In December 2016, the Board approved the payment of a special cash dividend (Special Dividend) in the aggregate amount of approximately $1 billion ($2.32 per share of common stock) to holders of record of our common stock on December 19, 2016. The dividend was funded using borrowings under the Vistra Operations Credit Facilities.

Dividend Restrictions — The agreement governing the Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2018, Vistra Operations can distribute approximately $9.3 billion to Vistra Energy Corp. (the Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to the Parent was partially reduced by distributions made by Vistra Operations to Parent during the years ended December 31, 2018 and 2017 of approximately $4.7 billion and $1.1 billion, respectively. In February 2019, Vistra Operations made an additional distribution to the Parent of approximately $1.45 billion. Additionally, Vistra Operations may make distributions to the Parent in amounts sufficient for the Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of the Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2018, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled approximately $6.5 billion.

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).

Accumulated Other Comprehensive Income — During the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016, we recorded changes in the funded status of our pension and other postretirement employee benefit liability totaling $9 million, $(23) million and $6 million, respectively. During the year ended December 31, 2018, $(3) million was reclassified from accumulated other comprehensive income and reported in other deductions. During the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, no amounts were reclassified from accumulated other comprehensive income.

Warrants — At the Merger Date, the Company entered into an agreement whereby holders of each outstanding warrant previously issued by Dynegy will be entitled to receive, upon exercise, the equity securities to which the holder would have been entitled to receive of Dynegy common stock converted into shares of Vistra Energy common stock at the Exchange Ratio. As of December 31, 2018, nine million warrants expiring in 2024 with an exercise price of $35.00 were outstanding, each of which can be redeemed for 0.652 share of Vistra Energy common stock. The warrants are recorded as equity in our consolidated balance sheet.

Tangible Equity Units — At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00% tangible equity units, each with a stated amount of $100.00 and each comprised of (i) a prepaid stock purchase contract that will deliver to the holder, not later than July 1, 2019, unless earlier redeemed or settled, not more than 4.0421 shares of Vistra Energy common stock and not less than 3.2731 shares of Vistra Energy common stock per contract based upon the applicable fixed settlement rate in the contract and (ii) a senior amortizing note with an outstanding principal amount of $38 million at the Merger Date that pays an equal quarterly cash installment of $1.75 per amortizing note (see Note 14). In the aggregate, the annual quarterly cash installments will be equivalent to a 7.00% cash payment per year with respect to each $100.00 stated amount of tangible equity units. The amortizing notes are accounted for as debt while the stock purchase contract is included in equity based on the fair value of the contract at the Merger Date (See Statements of Consolidated Equity and Note 14).

Predecessor Membership Interests

TCEH paid no dividends in the period from January 1, 2016 through October 2, 2016.

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

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 that reports to the Vistra Energy Chief Financial Officer.

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 18 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:



December 31, 2018
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	456	$	152	$	153	$	1	$	762
Interest rate swaps	—		77		—		—		77
Nuclear decommissioning trust – equity securities (c)	449		—		—		—		449
Nuclear decommissioning trust – debt securities (c)	—		443		—		—		443
Sub-total	$	905	$	672	$	153	$	1	1,731
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									278
Total assets									$	2,009
Liabilities:
Commodity contracts	$	557	$	766	$	288	$	1	$	1,612
Interest rate swaps	—		34		—		—		34
Total liabilities	$	557	$	800	$	288	$	1	$	1,646



December 31, 2017
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	47	$	98	$	75	$	2	$	222
Interest rate swaps	—		18		—		8		26
Nuclear decommissioning trust – equity securities (c)	468		—		—		—		468
Nuclear decommissioning trust – debt securities (c)	—		430		—		—		430
Sub-total	$	515	$	546	$	75	$	10	1,146
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									290
Total assets									$	1,436
Liabilities:
Commodity contracts	$	45	$	143	$	128	$	2	$	318
Interest rate swaps	—		—		—		8		8
Total liabilities	$	45	$	143	$	128	$	10	$	326

____________


(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 consolidated balance sheets.


(c)	The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets. See Note 23.


(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 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, fuel oil, uranium, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 18 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 December 31, 2018 and 2017:



December 31, 2018
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	22	$	(48	)	$	(26	)	Valuation Model	Hourly price curve shape (c)	$0 to $110/ MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$20 to $120/ MWh
Electricity and weather options	31		(192		)	(161		)	Option Pricing Model	Gas to power correlation (e)	15% to 95%
										Power volatility (e)	5% to 435%
Financial transmission rights	85		(20		)	65			Market Approach (f)	Illiquid price differences between settlement points (g)	$(10) to $50/ MWh
Other (h)	15		(28		)	(13		)
Total	$	153	$	(288	)	$	(135	)



December 31, 2017
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	12	$	(33	)	$	(21	)	Valuation Model	Hourly price curve shape (c)	$0 to $40/ MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$20 to $70/ MWh
Electricity and weather options	—		(91		)	(91		)	Option Pricing Model	Gas to power correlation (e)	30% to 100%
										Power volatility (e)	5% to 180%
Financial transmission rights	45		(4		)	41			Market Approach (f)	Illiquid price differences between settlement points (g)	$0 to $15/ MWh
Other (h)	18		—			18
Total	$	75	$	(128	)	$	(53	)

____________

(a)

Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, NYISO, ISO-NE and MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within are referred to as congestion revenue rights in ERCOT and financial transmission rights in PJM, NYISO, ISO-NE and MISO regions. Electricity options consist of physical electricity options and spread options.


(b)	The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.


(c)	Primarily based on the historical range of forward average hourly ERCOT North Hub prices.


(d)	Primarily based on historical forward ERCOT power price and heat rate variability.


(e)	Based on historical forward correlation and volatility within ERCOT.


(f)	While we use the market approach, there is insufficient market data to consider the valuation liquid.


(g)	Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.


(h)	Other includes contracts for natural gas, coal options and emissions.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016. See the table below for discussion of transfers between Level 2 and Level 3 for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016.



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Net asset (liability) balance at beginning of period (a)	$	(53	)	$	83		$	81		$	37
Total unrealized valuation gains (losses)	(363		)	(136		)	31			122
Purchases, issuances and settlements (b):
Purchases	146			69			15			37
Issuances	(41		)	(22		)	(7		)	(20		)
Settlements	76			(106		)	(30		)	(51		)
Transfers into Level 3 (c)	4			4			3			1
Transfers out of Level 3 (c)	133			71			(10		)	1
Net liabilities assumed in connections with the Merger	(37		)	—			—			—
Earn-out provision (d)	—			(16		)	—			—
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) (e)	—			—			—			(30		)
Net change (f)	(82		)	(136		)	2			60
Net asset (liability) balance at end of period	$	(135	)	$	(53	)	$	83		$	97
Unrealized valuation gains (losses) relating to instruments held at end of period	$	(174	)	$	(98	)	$	28		$	98

____________


(a)	The beginning balance for the Successor period from October 3, 2016 through December 31, 2016 reflects a $16 million adjustment to the fair value of certain Level 3 assets driven by power prices utilized by the Successor for unobservable delivery periods.


(b)	Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received.


(c)	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. For the years ended December 31, 2018 and 2017, transfers out of Level 3 primarily consists of electricity derivatives where forward pricing inputs have become observable.


(d)	Represents initial fair value of the earn-out provision agreed to as part of the Odessa Acquisition. See Note 3.


(e)	Includes fair value of Level 3 assets and liabilities as of the purchase date and any related rolloff between the purchase date and the period ended October 2, 2016.

(f)

Activity excludes change in fair value in the month positions settle. For the Successor period, substantially all changes in values of commodity contracts (excluding the net liabilities assumed in connection with the Merger and the initial fair value of the earn-out provision related to the Odessa Acquisition in 2017) are reported as operating revenues in our statements of consolidated income (loss). For the Predecessor period, substantially all changes in values of commodity contracts (excluding net liabilities assumed in the Lamar and Forney Acquisition in 2016) are reported as net gain from commodity hedging and trading activities in the statements of consolidated income (loss).

Derivative Instruments and Hedging Activities Disclosure [Abstract]

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Commodity And Other Derivative Contractual Assets And Liabilities

12 Months Ended

Dec. 31, 2018

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 17 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, uranium and emissions 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 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 are reported in our 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 consolidated balance sheets at December 31, 2018 and 2017. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.



	December 31, 2018
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	707	$	22	$	1		$	—		$	730
Noncurrent assets	54		55		—			—			109
Current liabilities	—		—		(1,374		)	(2		)	(1,376		)
Noncurrent liabilities	—		—		(238		)	(32		)	(270		)
Net assets (liabilities)	$	761	$	77	$	(1,611	)	$	(34	)	$	(807	)



	December 31, 2017
	Derivative Assets					Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps			Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	190	$	—		$	—		$	—		$	190
Noncurrent assets	30		22			2			4			58
Current liabilities	—		(4		)	(216		)	(4		)	(224		)
Noncurrent liabilities	—		—			(102		)	—			(102		)
Net assets (liabilities)	$	220	$	18		$	(316	)	$	—		$	(78	)

At December 31, 2018 and 2017, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects. 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.



	Successor								Predecessor
	Year Ended December 31,					Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Derivative (statements of consolidated income (loss) presentation)	2018			2017		Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Commodity contracts (Operating revenues)	$	(855	)	$	56	$	(92	)	$	—
Commodity contracts (Fuel, purchased power costs and delivery fees)	18			6		21			—
Commodity contracts (Net gain from commodity hedging and trading activities)	—			—		—			194
Interest rate swaps (Interest expense and related charges)	(11		)	2		(11		)	—
Net gain (loss)	$	(848	)	$	64	$	(82	)	$	194

In conjunction with fresh start reporting, the balances in accumulated other comprehensive income were eliminated from our 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 for the Predecessor period from January 1, 2016 through October 2, 2016. There were no amounts recognized in OCI for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016.

Balance Sheet Presentation of Derivatives

We elect to report derivative assets and liabilities in our 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 consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that, beginning in January 2017, are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.

The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:



	December 31, 2018												December 31, 2017
	Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)			Net Amounts			Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)			Net Amounts
Derivative assets:
Commodity contracts	$	761		$	(593	)	$	(1	)	$	167		$	220		$	(113	)	$	(1	)	$	106
Interest rate swaps	77			(26		)	—			51			18			—			—			18
Total derivative assets	838			(619		)	(1		)	218			238			(113		)	(1		)	124
Derivative liabilities:
Commodity contracts	(1,611		)	593			109			(909		)	(316		)	113			1			(202		)
Interest rate swaps	(34		)	26			—			(8		)	—			—			—			—
Total derivative liabilities	(1,645		)	619			109			(917		)	(316		)	113			1			(202		)
Net amounts	$	(807	)	$	—		$	108		$	(699	)	$	(78	)	$	—		$	—		$	(78	)

____________


(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.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at December 31, 2018 and 2017:



	December 31, 2018		December 31, 2017
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	7,011		1,259		Million MMBtu
Electricity	317,572		114,129		GWh
Financial Transmission Rights (b)	172,611		110,913		GWh
Coal	45		2		Million U.S. tons
Fuel oil	60		5		Million gallons
Uranium	50		325		Thousand pounds
Emissions	10		—		Million tons
Interest rate swaps – floating/fixed (c)	$	7,717	$	3,000	Million U.S. 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 ISOs or RTOs.


(c)	Includes notional amounts of interest rate swaps with maturity dates through July 2026.

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:



	December 31,
	2018			2017
Fair value of derivative contract liabilities (a)	$	(856	)	$	(204	)
Offsetting fair value under netting arrangements (b)	218			103
Cash collateral and letters of credit	190			41
Liquidity exposure	$	(448	)	$	(60	)

____________


(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 December 31, 2018, total credit risk exposure to all counterparties related to derivative contracts totaled $1.095 billion (including associated accounts receivable). The net exposure to those counterparties totaled $344 million at December 31, 2018 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $78 million. At December 31, 2018, the credit risk exposure to the banking and financial sector represented 62% of the total credit risk exposure and 22% 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.

Pension and Other Postretirement Employee Benefits (OPEB) Plans Pension and Other Postretirment Employee Benefits (OPEB) Plans

12 Months Ended

Dec. 31, 2018

Compensation and Retirement Benefits Disclosures [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS

On the Effective Date, the EFH Retirement Plan was transferred to Vistra Energy pursuant to a separation agreement between Vistra Energy and EFH Corp. As of the Effective Date, Vistra Energy is the plan sponsor of the Vistra Energy Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. As Vistra Energy accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra Energy's share of the plan assets and obligations are reported in the pension benefit information presented below. After amendments in 2012, employees in the Retirement Plan now consist entirely of active and retired collective bargaining unit employees. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations.

Vistra Energy and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service.

Prior to the Merger, Dynegy provided pension and OPEB benefits to certain of its employees and retirees. At the Merger Date, Vistra Energy assumed these plans and the excess of the benefit obligations over the fair value of plan assets was recognized as a liability (see Note 2). Benefit obligations assumed totaled $539 million and the fair value of plan assets assumed totaled $459 million, and the net unfunded liability was recorded as $15 million to other noncurrent assets, $2 million to other current liabilities and $93 million to other noncurrent liabilities in the consolidated balance sheets.

Effective January 1, 2018, Vistra Energy entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra Energy (or its predecessors) are split between Oncor and Vistra Energy. Prior to January 1, 2018, coverage for Split Participants was provided by the Oncor OPEB plan, with Vistra Energy retaining its portion of the liability for coverage for Split Participants. In addition, Vistra Energy is the sponsor of an OPEB plan that certain EFH Corp. retirees participate in. As Vistra Energy accounts for its interest in these OPEB plans as multiple employer plans, only Vistra Energy's share of the plan assets and obligations are reported in the OPEB information presented below.

Pension and OPEB Costs



	Successor						Predecessor
	Year Ended December 31, 2018		Year Ended December 31, 2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Pension costs	$	14	$	6	$	2	$	4
OPEB costs	9		6		2		—
Total benefit costs recognized as expense	$	23	$	12	$	4	$	4

Market-Related Value of Assets Held in Postretirement Benefit Trusts

We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

Detailed Information Regarding Pension Benefits

The following information is based on a December 31, 2018, 2017 and 2016 measurement dates:



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate (Vistra Energy Plan)	3.74		%	4.31		%	3.79		%
Discount rate (Dynegy Plan & EEI Plan)	4.05		%	—		%	—		%
Expected return on plan assets (Vistra Energy Plan)	4.56		%	4.86		%	4.89		%
Expected return on plan assets (Dynegy Plan)	5.94		%	—		%	—		%
Expected return on plan assets (EEI Plan)	4.74		%	—		%	—		%
Expected rate of compensation increase (Vistra Energy Plan)	3.62		%	3.50		%	3.50		%
Expected rate of compensation increase (Dynegy Plan & EEI Plan)	3.50		%	—		%	—		%
Interest crediting rate for cash balance plans (Vistra Energy Plan)	3.50		%	4.00		%	4.00		%
Interest crediting rate for cash balance plans (Dynegy Plan & EEI Plan)	4.25		%	—		%	—		%
Components of Net Pension Cost:
Service cost	$	15		$	5		$	2
Interest cost	21			6			1
Expected return on assets	(23		)	(5		)	(1		)
Immediate pension cost	$	1		$	—		$	—
Net periodic pension cost	$	14		$	6		$	2
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss	$	14		$	3		$	(4	)
Total recognized in net periodic benefit cost and other comprehensive income	$	28		$	9		$	(2	)
Assumptions Used to Determine Benefit Obligations:
Discount rate (Vistra Plan)	4.37		%	3.74		%	4.31		%
Expected rate of compensation increase (Vistra Plan)	3.35		%	3.62		%	3.50		%
Discount rate (Dynegy Plan)	4.37		%	—		%	—		%
Expected rate of compensation increase (Dynegy Plan)	3.35		%	—		%	—		%
Interest crediting rate for cash balance plans (Vistra Energy Plan)	3.50		%	3.50		%	4.00		%
Interest crediting rate for cash balance plans (Dynegy Plan & EEI)	3.50		%	—		%	—		%

For the year ended December 31, 2018, the net actuarial loss of $14 million was driven by losses attributable to actual asset performance falling short of expectations and plan experience different than expected, partially offset by gains attributable to increasing discount rates due to changes in the corporate bond markets, economic assumption updates to reflect current market conditions and life expectancy projection updates.

For the year ended December 31, 2017, the net actuarial loss of $3 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and demographic assumption updates to reflect current expectations, partially offset by gains attributable to actual asset performance exceeding expectations, economic assumption updates to reflect current market conditions, life expectancy projection updates and plan experience different than expected.

For the period from October 3, 2016 through December 31, 2016, the net actuarial gain of $4 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by losses attributable to actual asset performance falling short of expectations.



	Successor
	Year Ended December 31,
	2018			2017
Change in Pension Obligation:
Projected benefit obligation at beginning of period	$	163		$	144
Acquisitions	502			—
Service cost	15			5
Interest cost	21			6
Settlement	(28		)	—
Actuarial (gain) loss	(34		)	13
Benefits paid	(24		)	(5		)
Projected benefit obligation at end of year	$	615		$	163
Accumulated benefit obligation at end of year	$	611		$	157
Change in Plan Assets:
Fair value of assets at beginning of period	$	128		$	117
Acquisitions	428			—
Employer contributions	12			—
Settlement	(28		)	—
Actual gain (loss) on assets	(26		)	16
Benefits paid	(24		)	(5		)
Fair value of assets at end of year	$	490		$	128
Funded Status:
Projected pension benefit obligation	$	(615	)	$	(163	)
Fair value of assets	490			128
Funded status at end of year	$	(125	)	$	(35	)
Amounts Recognized in the Balance Sheet Consist of:
Other current liabilities	$	—		$	—
Other noncurrent liabilities	(125		)	(35		)
Net liability recognized	$	(125	)	$	(35	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net gain (loss)	$	(13	)	$	1

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.



	December 31,
	2018		2017
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	615	$	163
Accumulated benefit obligation	$	611	$	157
Plan assets	$	490	$	128

Pension Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets.

The target asset allocation ranges of pension plan investments by asset category are as follows:



	Target Allocation Ranges
Asset Category:	Vistra Energy Plan				Dynegy Plan				EEI Plan
Fixed income	65	%	-	75%	45	%	-	55%	43	%	-	53%
Global equity securities	16	%	-	24%	29	%	-	37%	30	%	-	38%
Real estate	4	%	-	8%	8	%	-	12%	9	%	-	13%
Credit strategies	3	%	-	7%	6	%	-	10%	6	%	-	10%

Expected Long-Term Rate of Return on Assets Assumption

The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.



	Retirement Plan
	Expected Long-Term Rate of Return
Asset Class:	Vistra Energy Plan		Dynegy Plan		EEI Plan
Fixed income securities	4.0	%	3.9	%	3.9	%
Global equity securities	7.5	%	7.5	%	7.5	%
Real estate	5.4	%	5.4	%	5.4	%
Credit strategies	6.8	%	6.8	%	6.8	%
Weighted average	4.8	%	5.3	%	5.6	%

Fair Value Measurement of Pension Plan Assets

At December 31, 2018 and 2017, the Retirement Plan assets measured at fair value on a recurring basis consisted of the following:



	December 31,
	2018								2017
	Level 1		Level 2			Total			Level 2
Asset Category:
Interest-bearing cash	$	—	$	(6	)	$	(6	)	$	(7	)
Fixed income securities:
Corporate bonds (a)	57		61			118			65
U.S. Treasuries	—		25			25			29
Other (b)	—		6			6			7
Total assets categorized as Level 1 or 2	57		86			143			94
Assets measured at net asset value (c):
Commingled trusts						18			2
Equity securities:
U.S.						119			14
International						73			13
Fixed income securities:
Corporate bonds (a)						137			5
Total assets measured at net asset value						347			34
Total assets						$	490		$	128

___________


(a)	Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.


(b)	Other consists primarily of taxable municipal bonds.


(c)	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. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to total Vistra Retirement Plan assets.

Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on a December 31, 2018 measurement date:



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate (Vistra Energy Plan)	3.67		%	4.11		%	4.00		%
Discount rate (Oncor Plan)	—		%	4.18		%	3.69		%
Discount rate (Dynegy Plan)	4.04		%	—		%	—		%
Expected return on plan assets (EEI Union)	5.10		%	—		%	—		%
Expected return on plan assets (EEI Salaried)	4.47		%	—		%	—		%
Components of Net Postretirement Benefit Cost:
Service cost	$	2		$	2		$	1
Interest cost	5			4			1
Expected return on plan assets	(1		)	—			—
Amortization of unrecognized amounts	3			—			—
Plan amendments (a)	—			—			(4		)
Net periodic OPEB cost (income)	$	9		$	6		$	(2	)
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss and prior service (credit) cost	$	(6	)	$	26		$	(5	)
Total recognized in net periodic benefit cost and other comprehensive income	$	3		$	32		$	(7	)
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate (Vistra Energy Plan)	4.35		%	3.67		%	4.11		%
Discount rate (Split-Participant Plan)	4.35		%	3.67		%	—		%
Discount rate (Oncor Plan)	—		%	—		%	4.18		%
Discount rate (Dynegy Plan)	4.35		%	—		%	—		%
Expected return on plan assets (EEI Union)	5.36		%	—		%	—		%
Expected return on plan assets (EEI Salaried)	4.70		%	—		%	—		%

___________


(a)	Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees.

For the year ended December 31, 2018, the net actuarial gain of $7 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, life expectancy projection updates and updates to health care related assumptions, partially offset by losses attributable to actual asset performance falling short of expectations and plan experience different than expected.

For the year ended December 31, 2017, the net actuarial loss of $15 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets, demographic assumption updates to reflect current expectations and updates to health care related assumptions, partially offset by gains attributable to life expectancy projection updates and plan experience different than expected.

For the period from October 3, 2016 through December 31, 2016, the net actuarial gain of $5 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets and plan experience different than expected.



	Year Ended December 31,
	2018			2017
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	115		$	88
Acquisition	37			—
Service cost	2			2
Interest cost	5			4
Participant contributions	2			2
Plan amendments (a)	4			11
Actuarial (gain) loss	(9		)	15
Benefits paid	(12		)	(7		)
Benefit obligation at end of year	$	144		$	115
Change in Plan Assets:
Fair value of assets at beginning of year	$	—		$	—
Acquisition	32			—
Employer contributions	8			5
Participant contributions	2			2
Benefits paid	(12		)	(7		)
Actual loss on assets	(1		)	—
Fair value of assets at end of year	$	29		$	—
Funded Status:
Benefit obligation	$	(144	)	$	(115	)
Fair value of assets	29			—
Funded status at end of year	$	(115	)	$	(115	)
Amounts Recognized on the Balance Sheet Consist of:
Other noncurrent assets	$	14		$	—
Other current liabilities	$	(8	)	$	(6	)
Other noncurrent liabilities	(121		)	(109		)
Net liability recognized	$	(115	)	$	(115	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss and prior service cost	$	15		$	20

___________


(a)	For the year ended December 31, 2018, plan amendments relate to changes in Dynegy plans and retiree medical cost structure. For the year ended December 31, 2017, plan amendments relate to the contractual arrangement with Oncor covering Split Participants.

The following tables provide information regarding the assumed health care cost trend rates.



	Successor
	December 31, 2018		December 31, 2017
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year	6.70	%	7.00	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2026		2026
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year	9.90	%	10.66	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2027		2026

Fair Value Measurement of OPEB Plan Assets

At December 31, 2018, the Vistra Energy OPEB plan assets measured at fair value on a recurring basis totaled $29 million and consisted of $21 million of U.S equities classified as Level 1 and $8 million of U.S. Treasuries classified as Level 2.

Significant Concentrations of Risk

The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.

Assumed Discount Rate

We selected the assumed discount rate using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2018 consisted of 377 corporate bonds with an average rating of AA using Moody's, Standard & Poor's Rating Services and Fitch Ratings, Ltd. ratings.

Contributions

Successor — For the Successor period for the year ended December 31, 2018, a contribution totaling $12 million was made to the Retirement Plan. No contributions were made to the Retirement Plan for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016. No contributions to the Retirement Plan are expected to be made in 2019. OPEB plan funding for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 totaled $8 million, $5 million and $1 million, respectively, and funding in 2019 is expected to total $8 million.

Predecessor — In September 2016, a cash contribution totaling $2 million was made to the EFH Retirement Plan, all of which was contributed by our Predecessor. OPEB plan funding for the Predecessor period from January 1, 2016 through October 2, 2016 totaled $3 million.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:



	2019		2020		2021		2022		2023		2024-28
Pension benefits	$	46	$	45	$	46	$	46	$	46	$	216
OPEB	$	10	$	11	$	11	$	11	$	11	$	49

Qualified Savings Plans

Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the Traditional Retirement Plan Formula) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options.

At the Merger Date, Vistra Energy assumed Dynegy's participant-directed defined contribution plan. In January 2019, this plan was merged into the Thrift Plan.

Aggregate employer contributions to the qualified savings plans totaled $24 million, $19 million, $5 million and $16 million for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.

Stock-Based Compensation (Notes)

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

STOCK-BASED COMPENSATION

Vistra Energy 2016 Omnibus Incentive Plan

On the Effective Date, the Vistra Energy board of directors (Board) adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards and other forms of awards granted or denominated in shares of Vistra Energy common stock, as well as certain cash-based awards.

If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra Energy common stock underlying any unexercised award shall again be available for awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra Energy common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation.

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra Energy stockholders.

Assumption of Dynegy Stock Compensation Plans

At the Merger Date, Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra Energy's common stock, after giving effect to the Exchange Ratio.



Instrument Type	Dynegy Awards Prior to the Merger Date	Vistra Awards Converted at the Merger Date	Fair Value of Awards (a)
Stock Options	4,096,027	2,670,610	$	10
Restricted Stock Units	5,718,148	3,056,689	61
Performance Units	1,538,133	938,721	18
Total			$	89

____________


(a)	$26 million was attributable to pre-combination service and considered part of the purchase price (see Note 2). $33 million was recognized immediately as compensation expense due to accelerated vesting as a result of the Merger. $30 million will be amortized as compensation expense over the remaining service period and is recorded in additional paid in capital in the consolidated balance sheet.

Stock-Based Compensation Expense

Stock-based compensation expense is reported as SG&A in the statement of consolidated net income (loss) as follows:



	Successor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016
Total stock-based compensation expense	$	73		$	19		$	3
Income tax benefit	(15		)	(7		)	(1		)
Stock based-compensation expense, net of tax	$	58		$	12		$	2

Stock Options

The fair value of each stock option is estimated on the date of grant using a Black-Scholes option-pricing model. The risk-free interest rate used in the option valuation model was based on yields available on the grant dates for U.S. Treasury Strips with maturity consistent with the expected life assumption. The expected term of the option represents the period of time that options granted are expected to be outstanding and is based on the SEC Simplified Method (midpoint of average vesting time and contractual term). Expected volatility is based on an average of the historical, daily volatility of a peer group selected by Vistra Energy over a period consistent with the expected life assumption ending on the grant date. We assumed no dividend yield in the valuation of the options. These options may be exercised over either three- or four-year graded vesting periods and will expire 10 years from the grant date.

The 2016 Incentive Plan includes an anti-dilutive provision that requires any outstanding option awards to be adjusted for the effect of equity restructurings. In March 2017, the Board declared that the exercise price of each outstanding option be reduced by $2.32, the amount per share of common stock related to the Special Dividend (see Note 16).

Issuance of Merger-related Stock Options — At the Merger Date, we issued 5.2 million stock options to certain members of management, which are subject to performance and service conditions for vesting. The performance condition is based on the Company's achievement of certain merger related targets measured as of December 31, 2019. Compensation cost has been recognized in 2018 based on graded vesting over 4 and 5 years since the date of issuance because we estimate achievement of the target is likely to occur.

Stock options outstanding at December 31, 2018 are all held by current employees. The following table summarizes our stock option activity:



	Successor
	Year Ended December 31, 2018
	Stock Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value (in millions)
Total outstanding at beginning of period	8,136		$	14.44	9.0	$	32.4
Awards converted at Merger Date	2,671		$	23.19
Granted	5,268		$	19.67
Exercised	(1,082	)	$	13.91
Forfeited or expired	(494	)	$	15.14
Total outstanding at end of period	14,499		$	17.97	7.3	$	85.1
Exercisable at December 31, 2018	4,696		$	18.88	5.2	$	32.6

At December 31, 2018, $48 million of unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 3 years.

Restricted Stock Units

The following table summarizes our restricted stock unit activity:



	Successor
	Year Ended December 31, 2018
	Restricted Stock Units (in thousands)		Weighted Average Grant Date Fair Value		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value (in millions)
Total outstanding at beginning of period	2,375		$	16.91	1.9	$	43.5
Awards converted at Merger Date	3,057		$	15.52
Granted	133		$	22.41
Exercised	(2,114	)	$	15.48
Forfeited or expired	(225	)	$	16.69
Total outstanding at end of period	3,226		$	16.77	1.1	$	73.8
Expected to vest	3,222		$	16.85	1.0	$	73.7

At December 31, 2018, $40 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 3 years.

Performance Stock Units

In October 2017, we issued Performance Stock Units (PSUs) to certain members of management. As of December 31, 2018, we had not yet established the significant terms of the PSUs relevant to vesting (scorecard, thresholds, and targets) for the entire measurement period; therefore, a grant date for financial accounting purposes has not occurred.

Related Party Transactions

12 Months Ended

Dec. 31, 2018

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, which was declared effective by the SEC in May 2017. The registration statement was amended in March 2018. Pursuant to the Registration Rights Agreement, in June 2018, we filed a post-effective amendment to the Form S-1 registration statement on Form S-3, which was declared effective by the SEC in July 2018. Among other things, under the terms of the Registration Rights Agreement:


•	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 each of the years ended December 31, 2018 and 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 10 for discussion of the TRA.

Share Repurchase Transaction

In November 2018, the disinterested members of the Board considered and approved (in accordance with the Company's corporate governance guidelines) a share repurchase transaction, whereby Apollo Management Holdings L.P. (Apollo) and the Company, in a privately negotiated transaction, agreed for the Company to directly repurchase 5 million shares from Apollo. This purchase was part of Apollo's larger, 17 million share block trade, with the remaining 12 million shares being sold in a separate unregistered Rule 144 secondary block trade to a broker-dealer, who placed all 12 million shares with institutional investors. The Company repurchased the 5 million shares at the same discounted price (discounted from the November 19, 2018 closing price) that the participating broker paid for the 12 million shares it purchased, and the Company did not pay any additional fees to the participating broker for the 5 million shares it repurchased.

Predecessor

See Note 5 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 and a tax matters 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 $700 million for the Predecessor period from January 1, 2016 through October 2, 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 $157 million for the Predecessor period from January 1, 2016 through October 2, 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 consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in asset retirement obligations in our consolidated balance sheets. The delivery fee surcharges remitted to our Predecessor totaled $15 million for the Predecessor period from January 1, 2016 through October 2, 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 Predecessor period from January 1, 2016 through October 2, 2016, our Predecessor made income tax payments to EFH Corp. totaling $22 million.

•

Contributions to the EFH Corp. retirement plan by both Oncor and TCEH in 2014, 2015 and 2016 resulted in the EFH Corp. retirement plan being fully funded as calculated under the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In September 2016, a cash contribution totaling $2 million was made to the EFH Corp. retirement plan, all of which was contributed by TCEH, which resulted in the EFH Retirement Plan continuing to be fully funded as calculated under the provisions of ERISA. On the Effective Date, the EFH Retirement Plan was transferred to Vistra Energy pursuant to a separation agreement between Vistra Energy and 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 debt or debt securities issued by our Predecessor in open market transactions or through loan syndications.

Segment Information

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Segment Information


.	SEGMENT INFORMATION

The operations of Vistra Energy are aligned into six reportable business segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE, (v) MISO and (vi) Asset Closure. Our chief operating decision maker reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations.

The Retail segment is engaged in retail sales of electricity and related services to residential, commercial and industrial customers. Substantially all of these activities are conducted by TXU Energy and Value Based Brands in Texas, Dynegy Energy Services in Massachusetts, Ohio, Illinois and Pennsylvania and Homefield Energy in Illinois. Prior to the Merger, the Retail segment was referred to as the Retail Electricity segment.

The ERCOT, PJM, NY/NE (comprising NYISO and ISO-NE) and MISO segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely within their respective ISO market. The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets served by businesses acquired in the Merger. Prior to the Merger, the ERCOT segment was referred to as the Wholesale Generation segment.

As discussed in Note 1, the Asset Closure segment was established effective January 1, 2018. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines. Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra Energy's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. We have not allocated any unrealized gains or losses on commodity risk management activities to the Asset Closure segment for the generation plants that were retired in January, February and May 2018.

Corporate and Other represents the remaining non-segment operations consisting primarily of (i) general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating segments and (ii) CAISO operations.

Except as noted in Note 1, the accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. Our chief operating decision maker uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on US GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments.



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Operating revenues (a)
Retail	$	5,597		$	4,058		$	912
ERCOT	2,634			1,794			212
PJM	1,725			—			—
NY/NE	817			—			—
MISO	720			—			—
Asset Closure	50			964			238
Corporate and Other (b)	208			—			—
Eliminations	(2,607		)	(1,386		)	(171		)
Consolidated operating revenues	$	9,144		$	5,430		$	1,191
Depreciation and amortization
Retail	$	(318	)	$	(430	)	$	(153	)
ERCOT	(416		)	(229		)	(53		)
PJM	(413		)	—			—
NY/NE	(152		)	—			—
MISO	(9		)	—			—
Asset Closure	—			(1		)	—
Corporate and Other (b)	(86		)	(40		)	(11		)
Eliminations				1			$	1
Consolidated depreciation and amortization	$	(1,394	)	$	(699	)	$	(216	)
Operating income (loss)
Retail	$	690		$	461		$	111
ERCOT	(70		)	(118		)	(271		)
PJM	100			—			—
NY/NE	70			—			—
MISO	36			—			—
Asset Closure	(50		)	(68		)	16
Corporate and Other (b)	(281		)	(78		)	(17		)
Eliminations	(4		)	1			—
Consolidated operating income (loss)	$	491		$	198		$	(161	)
Interest expense and related charges
Retail	$	(7	)	$	—		$	—
ERCOT	(12		)	(21		)	1
PJM	(8		)	—			—
NY/NE	(2		)	—			—
MISO	(1		)	—			—
Corporate and Other (b)	(613		)	(252		)	(66		)
Eliminations	71			80			5
Consolidated interest expense and related charges	$	(572	)	$	(193	)	$	(60	)



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Income tax (expense) benefit (all Corporate and Other)	$	45		$	(504	)	$	70
Net income (loss)
Retail	$	712		$	495		$	114
ERCOT	(55		)	(114		)	(268		)
PJM	100			—			—
NY/NE	79			—			—
MISO	35			—			—
Asset Closure	(49		)	(63		)	17
Corporate and Other (b)	(876		)	(573		)	(26		)
Eliminations	(2		)	1			—
Consolidated net income (loss)	$	(56	)	$	(254	)	$	(163	)
Capital expenditures, excluding LTSA
Retail	$	1		$	—		$	5
ERCOT	283			150			84
PJM	41			—			—
NY/NE	10			—			—
MISO	3			—			—
Corporate and Other (b)	58			26			—
Consolidated capital expenditures	$	396		$	176		$	89

____________


(a)	The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Retail	$	(12	)	$	18		$	(6	)
ERCOT	(483		)	(305		)	(295		)
PJM	(50		)	—			—
NY/NE	(40		)	—			—
MISO	3			—			—
Corporate and Other (b)	(15		)	—			—
Eliminations (1)	217			154			113
Consolidated unrealized net losses from mark-to-market valuations of commodity positions included in operating revenues	$	(380	)	$	(133	)	$	(188	)

____________


(1)	Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.


(b)	Other includes CAISO operations. Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate net income.



	December 31,
	2018			2017
Total assets
Retail	$	7,699		$	6,156
ERCOT	9,347			6,821
PJM	7,188			—
NY/NE	2,722			—
MISO	836			—
Asset Closure	254			248
Corporate and Other and Eliminations	(2,022		)	1,375
Consolidated total assets	$	26,024		$	14,600

Prior to the Effective Date, our Predecessor's chief operating decision maker reviewed the retail electricity, wholesale generation and commodity risk management activities together. Consequently, there were no reportable business segments for TCEH.

Supplementary Financial Information

12 Months Ended

Dec. 31, 2018

Supplementary Financial Information [Abstract]

Supplementary Financial Information

SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions



	Successor						Predecessor
	Year Ended December 31,				Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
	2018		2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Other income:
Office space sublease rental income (a)	$	8	$	11	$	2	$	—
Mineral rights royalty income (b)	—		3		1		3
Sale of land (b)	3		4		—		—
Curtailment gain on employee benefit plans (a)	—		—		4		—
Insurance settlement	16		—		—		9
Interest income	18		15		1		3
All other	2		4		2		4
Total other income	$	47	$	37	$	10	$	19
Other deductions:
Write-off of generation equipment (b)	—		2		—		45
Adjustment to asbestos liability	—		—		—		11
All other	5		3		—		19
Total other deductions	$	5	$	5	$	—	$	75

____________


(a)	Reported in Corporate and Other non-segment (Successor period only).


(b)	Reported in ERCOT segment (Successor period only).

Restricted Cash



	December 31, 2018				December 31, 2017
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the Vistra Operations Credit Facilities (Note 14)	$	—	$	—	$	—	$	500
Amounts related to restructuring escrow accounts	57		—		59		—
Total restricted cash	$	57	$	—	$	59	$	500

Trade Accounts Receivable



	December 31,
	2018			2017
Wholesale and retail trade accounts receivable	$	1,106		$	596
Allowance for uncollectible accounts	(19		)	(14		)
Trade accounts receivable — net	$	1,087		$	582

Gross trade accounts receivable at December 31, 2018 and 2017 included unbilled retail revenues of $350 million and $251 million, respectively.

Allowance for Uncollectible Accounts Receivable



	Successor								Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Allowance for uncollectible accounts receivable at beginning of period	$	14		$	10		$	—	$	9
Increase for bad debt expense	56			43			10		20
Decrease for account write-offs	(51		)	(39		)	—		(16		)
Allowance for uncollectible accounts receivable at end of period	$	19		$	14		$	10	$	13

Inventories by Major Category



	December 31,
	2018		2017
Materials and supplies	$	286	$	149
Fuel stock	115		83
Natural gas in storage	11		21
Total inventories	$	412	$	253

Other Investments



	December 31,
	2018		2017
Nuclear plant decommissioning trust	$	1,170	$	1,188
Assets related to employee benefit plans (Note 19)	31		—
Land	49		49
Miscellaneous other	—		3
Total other investments	$	1,250	$	1,240

Investment in Unconsolidated Subsidiaries

On the Merger Date, we assumed Dynegy's 50% interest in Northeast Energy, LP (NELP), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At December 31, 2018, our estimated investment in NELP totaled $129 million based on our preliminary purchase price allocation and subsequent 2018 activity. Our risk of loss related to our equity method investment is limited to our investment balance (see Note 2).

For the year ended December 31, 2018, equity earnings related to our investment in NELP totaled $17 million, recorded in equity in earnings (loss) of unconsolidated investment in our statements of consolidated net income (loss). For the year ended December 31, 2018, we received distributions totaling $17 million.

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 Electric Delivery Company LLC's (Oncor) 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 regulatory asset/liability (currently a regulatory asset reported in other noncurrent assets) that will ultimately be settled through changes in Oncor's delivery fees rates. If funds recovered from Oncor's customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra Energy, provided that Vistra Energy complied with PUCT rules and regulations regarding decommissioning trusts. A summary of investments in the fund follows:



	December 31, 2018
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	444	$	7	$	(8	)	$	443
Equity securities (c)	280		448		(1		)	727
Total	$	724	$	455	$	(9	)	$	1,170



	December 31, 2017
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	418	$	14	$	(2	)	$	430
Equity securities (c)	265		495		(2		)	758
Total	$	683	$	509	$	(4	)	$	1,188

____________


(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 government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of 3.69% and 3.55% at December 31, 2018 and 2017, respectively, and an average maturity of 8 years and 9 years at December 31, 2018 and 2017, respectively.


(c)	The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI Inc. EAFE Index for non-U.S. equity investments.

Debt securities held at December 31, 2018 mature as follows: $153 million in one to 5 years, $100 million in five to 10 years and $190 million after 10 years.

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Realized gains	$	2		$	9		$	1		$	3
Realized losses	$	(9	)	$	(11	)	$	—		$	(2	)
Proceeds from sales of securities	$	252		$	252		$	25		$	201
Investments in securities	$	(274	)	$	(272	)	$	(30	)	$	(215	)

Property, Plant and Equipment



	December 31,
	2018			2017
Power generation and structures	$	14,604		$	3,966
Land	642			540
Office and other equipment	182			120
Total	15,428			4,626
Less accumulated depreciation	(1,284		)	(282		)
Net of accumulated depreciation	14,144			4,344
Nuclear fuel (net of accumulated amortization of $189 million and $111 million)	191			158
Construction work in progress	277			318
Property, plant and equipment — net	$	14,612		$	4,820

Depreciation expense totaled $1.024 billion, $236 million, $54 million and $401 million for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.

Our property, plant and equipment consist of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements. At December 31, 2018, buildings and improvements includes a capital lease for an office building that totaled $62 million with accumulated depreciation of $11 million. The estimated remaining useful lives range from 1 to 35 years for our property, plant and equipment.

Asset Retirement and Mining Reclamation Obligations (ARO)

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of coal/lignite-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.

At December 31, 2018, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.276 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 consolidated balance sheet of $106 million in other noncurrent assets.

The following table summarizes the changes to these obligations, reported as asset retirement obligations (current and noncurrent liabilities) in our consolidated balance sheets, for the Successor period for the years ended December 31, 2018 and 2017:



	Nuclear Plant Decommissioning		Mining Land Reclamation			Coal Ash and Other			Total
Successor:
Liability at December 31, 2016	1,200		375			151			1,726
Additions:
Accretion	33		18			8			59
Adjustment for change in estimates (a)	—		81			44			125
Incremental reclamation costs (b)	—		—			62			62
Reductions:
Payments	—		(36		)	—			(36		)
Liability at December 31, 2017	1,233		438			265			1,936
Additions:
Accretion	43		22			28			93
Adjustment for change in estimates	—		56			(89		)	(33		)
Obligations assumed in the Merger	—		2			475			477
Reductions:
Payments	—		(76		)	(24		)	(100		)
Liability at December 31, 2018	1,276		442			655			2,373
Less amounts due currently	—		(106		)	(50		)	(156		)
Noncurrent liability at December 31, 2018	$	1,276	$	336		$	605		$	2,217

____________


(a)	Amounts primarily relate to the impacts of accelerating the ARO associated with the retirements of the Sandow 4, Sandow 5, Big Brown and Monticello plants (see Note 4).


(b)	Amounts primarily relate to liabilities incurred as part of acquiring certain real property through the Alcoa contract settlement (see Note 4).

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:



	December 31,
	2018		2017
Retirement and other employee benefits	$	270	$	166
Uncertain tax positions, including accrued interest	4		—
Other	66		54
Total other noncurrent liabilities and deferred credits	$	340	$	220

Fair Value of Debt



		December 31, 2018				December 31, 2017
Long-Term Debt (see Note 14):	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	5,820	$	5,599	$	4,323	$	4,334
Vistra Operations Senior Notes	Level 2	987		963		—		—
Vistra Energy Senior Notes	Level 2	3,819		3,765		—		—
7.000% Amortizing Notes	Level 2	23		24		—		—
Forward Capacity Agreements	Level 3	221		221		—		—
Equipment Financing Agreements	Level 3	102		102		—		—
Mandatorily redeemable subsidiary preferred stock	Level 2	70		70		70		70
Building Financing	Level 2	23		21		30		27

We determine fair value in accordance with accounting standards as discussed in Note 17. 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

The following table reconciles cash, cash equivalents and restricted cash reported in our statements of consolidated cash flows to the amounts reported in our balance sheets at December 31, 2018 and 2017:



	December 31,
	2018		2017
Cash and cash equivalents	$	636	$	1,487
Restricted cash included in current assets	57		59
Restricted cash included in noncurrent assets	—		500
Total cash, cash equivalents and restricted cash	$	693	$	2,046

The following table summarizes our supplemental cash flow information for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Cash payments related to:
Interest paid (a)	$	651		$	245		$	19		$	1,064
Capitalized interest	(12		)	(7		)	(3		)	(9		)
Interest paid (net of capitalized interest) (a)	$	639		$	238		$	16		$	1,055
Income taxes	$	67		$	63		$	(2	)	$	22
Reorganization items (b)	$	—		$	—		$	—		$	104
Noncash investing and financing activities:
Construction expenditures (c)	$	79		$	12		$	1		$	53
Vistra Energy common stock issued in the Merger (Notes 2 and 16)	$	2,245		$	—		$	—		$	—

____________


(a)	Predecessor period includes amounts paid for adequate protection.


(b)	Represents cash payments made by our Predecessor for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court.


(c)	Represents end-of-period accruals for ongoing construction projects.

Quarterly Information (Unaudited)

Unaudited results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a full year's operations because of seasonal and other factors. Quarterly amounts may not add to full year amounts due to rounding.



	Successor
	Quarter Ended
	March 31			June 30			September 30		December 31 (b)
2018(a):
Operating revenues	$	765		$	2,574		$	3,243	$	2,562
Operating income (loss)	$	(394	)	$	231		$	650	$	4
Net income (loss)	$	(306	)	$	105		$	331	$	(186	)
Net income (loss) attributable to Vistra Energy	$	(306	)	$	108		$	330	$	(186	)
Net income (loss) per weighted average share of common stock outstanding — basic	$	(0.71	)	$	0.21		$	0.62	$	(0.35	)
Net income (loss) per weighted average share of common stock outstanding — diluted	$	(0.71	)	$	0.20		$	0.61	$	(0.35	)
2017:
Operating revenues	$	1,357		$	1,296		$	1,833	$	944
Operating income (loss)	$	155		$	53		$	452	$	(462	)
Net income (loss)	$	78		$	(26	)	$	273	$	(579	)
Net income (loss) attributable to Vistra Energy	$	78		$	(26	)	$	273	$	(579	)
Net income (loss) per weighted average share of common stock outstanding — basic	$	0.18		$	(0.06	)	$	0.64	$	(1.35	)
Net income (loss) per weighted average share of common stock outstanding — diluted	$	0.18		$	(0.06	)	$	0.64	$	(1.35	)

____________


(a)	For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.

(b)

For the Successor quarter ended December 31, 2017, operating loss includes noncash charges of $183 million related to the generation facilities retirement announcements. Net loss reflects the retirements mentioned above as well as a $451 million reduction of deferred tax assets related to the decrease in the corporate tax rate due to the TCJA (see Note 9), partially offset by $117 million of impacts of the TRA.

Supplemental Condensed Consolidating Financial Information Supplemental Condensed Consolidating Financial Information (Notes)

12 Months Ended

Dec. 31, 2018

Supplemental Condensed Consolidating Financial Information [Abstract]

Supplemental Condensed Consolidating Financial Information [Text Block]

SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our senior notes are guaranteed by substantially all of our wholly owned subsidiaries. The following condensed consolidating financial statements present the financial information of (i) Vistra Energy Corp. (Parent), which is the ultimate parent company and issuer of the senior notes with effect as of the Merger Date, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Vistra Energy (Guarantor Subsidiaries), (iii) the non-guarantor subsidiaries of Vistra Energy (Non-Guarantor Subsidiaries) and (iv) the eliminations necessary to arrive at the information for Vistra Energy on a consolidated basis. The Guarantor Subsidiaries consist of the wholly owned subsidiaries, which jointly, severally, fully and unconditionally, guarantee the payment obligations under the senior notes. See Note 14 for discussion of the senior notes.

These statements should be read in conjunction with the consolidated financial statements and notes thereto of Vistra Energy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. The inclusion of Vistra Energy's subsidiaries as either Guarantor Subsidiaries or Non-Guarantor Subsidiaries in the condensed consolidating financial information is determined as of the most recent balance sheet date presented.

The Parent files a consolidated U.S. federal income tax return. All consolidated income tax expense or benefits and deferred tax assets and liabilities have been allocated to the respective subsidiary columns in accordance with the accounting rules that apply to separate financial statements of subsidiaries. In prior years, the Company had presented condensed financial information of the Parent in Schedule I under Item 15; for purposes of that schedule, consolidated income tax expense or benefits was reflected at the Parent.

Vistra Energy Corp. (Parent) received $4.668 billion, $1.505 billion and $1.0 billion in dividends from its consolidated subsidiaries in the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016, respectively.

Condensed Statements of Consolidating Income (Loss)

for the Year Ended December 31, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	9,043		$	174		$	(73	)	$	9,144
Fuel, purchased power costs and delivery fees	—			(4,968		)	(92		)	24			(5,036		)
Operating costs	—			(1,255		)	(42		)	—			(1,297		)
Depreciation and amortization	—			(1,337		)	(57		)	—			(1,394		)
Selling, general and administrative expenses	(266		)	(660		)	(49		)	49			(926		)
Operating income (loss)	(266		)	823			(66		)	—			491
Other income	9			41			—			(3		)	47
Other deductions	—			(6		)	1			—			(5		)
Interest expense and related charges	(257		)	(309		)	(9		)	3			(572		)
Impacts of Tax Receivable Agreement	(79		)	—			—			—			(79		)
Equity in earnings of unconsolidated investment	—			17			—			—			17
Income (loss) before income taxes	(593		)	566			(74		)	—			(101		)
Income tax expense	282			(284		)	47			—			45
Equity in earnings (loss) of subsidiaries, net of tax	257			(25		)	—			(232		)	—
Net income (loss)	(54		)	257			(27		)	(232		)	(56		)
Net loss attributable to noncontrolling interest	—			—			2			—			2
Net income (loss) attributable to Vistra Energy	$	(54	)	$	257		$	(25	)	$	(232	)	$	(54	)

Condensed Statements of Consolidating Income (Loss)

for the Year Ended December 31, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating revenues	$	—		$	5,430		$	—	$	—	$	5,430
Fuel, purchased power costs and delivery fees	—			(2,935		)	—		—		(2,935		)
Operating costs	—			(973		)	—		—		(973		)
Depreciation and amortization	—			(699		)	—		—		(699		)
Selling, general and administrative expenses	(47		)	(553		)	—		—		(600		)
Impairment of long-lived assets	—			(25		)	—		—		(25		)
Operating income (loss)	(47		)	245			—		—		198
Other income	—			37			—		—		37
Other deductions	—			(5		)	—		—		(5		)
Interest Income	4			(4		)	—		—		—
Interest expense and related charges	—			(193		)	—		—		(193		)
Impacts of Tax Receivable Agreement	213			—			—		—		213
Income before income taxes	170			80			—		—		250
Income tax benefit (expense)	80			(584		)	—		—		(504		)
Equity in earnings (losses) of subsidiaries, net of tax	(504		)	—			—		504		—
Net income (loss)	$	(254	)	$	(504	)	$	—	$	504	$	(254	)

Condensed Statements of Consolidating Income (Loss)

for the Period from October 3, 2016 through December 31, 2016

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues	$	—		$	1,191		$	—	$	—		$	1,191
Fuel, purchased power costs and delivery fees	—			(720		)	—		—			(720		)
Operating costs	—			(208		)	—		—			(208		)
Depreciation and amortization	—			(216		)	—		—			(216		)
Selling, general and administrative expenses	(7		)	(201		)	—		—			(208		)
Operating income (loss)	(7		)	(154		)	—		—			(161		)
Other income	—			10			—		—			10
Interest expense and related charges	—			(60		)	—		—			(60		)
Impacts of Tax Receivable Agreement	(22		)	—			—		—			(22		)
Income (loss) before income taxes	(29		)	(204		)	—		—			(233		)
Income tax expense	(204		)	274			—		—			70
Equity in earnings (loss) of subsidiaries, net of tax	70			—			—		(70		)	—
Net income (loss)	(163		)	70			—		(70		)	(163		)

Condensed Statements of Consolidating Comprehensive Income (Loss)

for the Year Ended December 31, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	(54	)	$	257		$	(27	)	$	(232	)	$	(56	)
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	—			(6		)	—			—			(6		)
Adoption of accounting standard	1			—			—			—			1
Total other comprehensive income	1			(6		)	—			—			(5		)
Comprehensive income (loss)	(53		)	251			(27		)	(232		)	(61		)
Comprehensive loss attributable to noncontrolling interest	—			—			2			—			2
Comprehensive income (loss) attributable to Vistra Energy	$	(53	)	$	251		$	(25	)	$	(232	)	$	(59	)

Condensed Statements of Consolidating Comprehensive Income (Loss)

for the Year Ended December 31, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net income (loss)	$	(254	)	$	(504	)	$	—	$	504	$	(254	)
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	(23		)	(29		)	—		29		(23		)
Total other comprehensive income	(23		)	(29		)	—		29		(23		)
Comprehensive income (loss)	$	(277	)	$	(533	)	$	—	$	533	$	(277	)

Condensed Statements of Consolidating Comprehensive Income (Loss)

for the Period from October 3, 2016 through December 31, 2016

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	(163	)	$	70	$	—	$	(70	)	$	(163	)
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	6			6		—		(6		)	6
Total other comprehensive income	6			6		—		(6		)	6
Comprehensive income (loss)	(157		)	76		—		(76		)	(157		)

Condensed Statements of Consolidating Cash Flows

for the Year Ended December 31, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(125	)	$	1,917		$	(321	)	$	—		$	1,471
Cash flows — financing activities:
Issuances of long-term debt	—			1,000			—			—			1,000
Repayments/repurchases of debt	(4,543		)	1,468			—			—			(3,075		)
Borrowings under accounts receivable securitization program	—			—			339						339
Cash dividend paid	—			(4,668		)	—			4,668			—
Stock repurchase	(763		)	—			—			—			(763		)
Debt tender offer and other financing fees	(179		)	(57		)	—			—			(236		)
Other, net	12			—			—			—			12
Cash provided by (used in) financing activities	(5,473		)	(2,257		)	339			4,668			(2,723		)
Cash flows — investing activities:
Capital expenditures	(24		)	(351		)	(3		)	—			(378		)
Nuclear fuel purchases	—			(118		)	—			—			(118		)
Cash acquired in the Merger	—			445			—			—			445
Development and growth expenditures	—			(31		)	(3		)	—			(34		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			252			—			—			252
Investments in nuclear decommissioning trust fund securities	—			(274		)	—			—			(274		)
Dividend received from subsidiaries	4,668									(4,668		)	—
Other, net	(1		)	7			—			—			6
Cash provided by (used in) investing activities	4,643			(70		)	(6		)	(4,668		)	(101		)
Net change in cash, cash equivalents and restricted cash	(955		)	(410		)	12			—			(1,353		)
Cash, cash equivalents and restricted cash — beginning balance	1,183			863			—			—			2,046
Cash, cash equivalents and restricted cash — ending balance	$	228		$	453		$	12		$	—		$	693

Condensed Statements of Consolidating Cash Flows

for the Year Ended December 31, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(108	)	$	1,494		$	—	$	—		$	1,386
Cash flows — financing activities:
Repayments/repurchases of debt	—			(191		)	—		—			(191		)
Cash dividend paid	—			(1,505		)	—		1,505			—
Debt financing fees	—			(8		)	—		—			(8		)
Other, net	—			(2		)	—		—			(2		)
Cash provided by (used in) financing activities	—			(1,706		)	—		1,505			(201		)
Cash flows — investing activities:
Capital expenditures	—			(114		)	—		—			(114		)
Nuclear fuel purchases	—			(62		)	—		—			(62		)
Development and growth expenditures	—			(190		)	—		—			(190		)
Odessa acquisition	(330		)	(25		)	—		—			(355		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			252			—		—			252
Investments in nuclear decommissioning trust fund securities	—			(272		)	—		—			(272		)
Dividend received from subsidiaries	1,505								(1,505		)	—
Other, net	—			14			—		—			14
Cash provided by (used in) investing activities	1,175			(397		)	—		(1,505		)	(727		)
Net change in cash, cash equivalents and restricted cash	1,067			(609		)	—		—			458
Cash, cash equivalents and restricted cash — beginning balance	116			1,472			—		—			1,588
Cash, cash equivalents and restricted cash — ending balance	$	1,183		$	863		$	—	$	—		$	2,046

Condensed Statements of Consolidating Cash Flows

for the Period from October 3, 2016 through December 31, 2016

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(36	)	$	117		$	—	$	—		$	81
Cash flows — financing activities:
Issuances of long-term debt	—			1,000			—		—			1,000
Cash dividend paid	—			(997		)	—		997			—
Special dividends	(992		)	—			—		—			(992		)
Other, net	1			(3		)	—		—			(2		)
Cash provided by (used in) financing activities	(991		)	—			—		997			6
Cash flows — investing activities:
Capital expenditures	—			(48		)	—		—			(48		)
Nuclear fuel purchases	—			(41		)	—		—			(41		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			25			—		—			25
Investments in nuclear decommissioning trust fund securities	—			(30		)	—		—			(30		)
Dividend received from subsidiaries	997			—			—		(997		)	—
Other, net	—			1			—		—			1
Cash provided by (used in) investing activities	997			(93		)	—		(997		)	(93		)
Net change in cash, cash equivalents and restricted cash	(30		)	24			—		—			(6		)
Cash, cash equivalents and restricted cash — beginning balance	146			1,448			—		—			1,594
Cash, cash equivalents and restricted cash — ending balance	$	116		$	1,472		$	—	$	—		$	1,588

Condensed Consolidating Balance Sheet as of December 31, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	171	$	453	$	12	$	—		$	636
Restricted cash	57		—		—		—			57
Advances to affiliates	11		11		—		(22		)	—
Trade accounts receivable — net	4		729		464		(110		)	1,087
Accounts receivable — affiliates	—		245		—		(245		)	—
Notes due from affiliates	—		101		—		(101		)	—
Income taxes receivable	—		1		—		(1		)	—
Inventories	—		391		21		—			412
Commodity and other derivative contractual assets	—		730		—		—			730
Margin deposits related to commodity contracts	—		361		—		—			361
Prepaid expense and other current assets	2		134		16		—			152
Total current assets	245		3,156		513		(479		)	3,435
Investments	—		1,218		32		—			1,250
Investment in unconsolidated subsidiary	—		131		—		—			131
Investment in affiliated companies	11,186		263		—		(11,449		)	—
Property, plant and equipment — net	15		14,017		580		—			14,612
Goodwill	—		2,068		—		—			2,068
Identifiable intangible assets — net	10		2,480		3		—			2,493
Commodity and other derivative contractual assets	—		109		—		—			109
Accumulated deferred income taxes	809		599		—		(72		)	1,336
Other noncurrent assets	255		330		5		—			590
Total assets	$	12,520	$	24,371	$	1,133	$	(12,000	)	$	26,024
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program	$	—	$	—	$	339	$	—		$	339
Advances from affiliates	—		—		22		(22		)	—
Long-term debt due currently	23		163		5		—			191
Trade accounts payable	2		928		121		(106		)	945
Accounts payable — affiliates	236		—		9		(245		)	—
Notes due to affiliates	—		—		101		(101		)	—
Commodity and other derivative contractual liabilities	—		1,376		—		—			1,376
Margin deposits related to commodity contracts	—		4		—		—			4
Accrued taxes	11		—		—		(1		)	10
Accrued taxes other than income	—		181		1		—			182
Accrued interest	48		29		4		(4		)	77
Asset retirement obligations	—		156		—		—			156
Other current liabilities	74		267		4		—			345
Total current liabilities	394		3,104		606		(479		)	3,625

Condensed Consolidating Balance Sheet as of December 31, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Long-term debt, less amounts due currently	3,819		7,027		28		—			10,874
Commodity and other derivative contractual liabilities	—		270		—		—			270
Accumulated deferred income taxes	—		—		82		(72		)	10
Tax Receivable Agreement obligation	420		—		—		—			420
Asset retirement obligations	—		2,203		14		—			2,217
Identifiable intangible liabilities — net	—		278		123		—			401
Other noncurrent liabilities and deferred credits	20		303		17		—			340
Total liabilities	4,653		13,185		870		(551		)	18,157
Total stockholders' equity	7,867		11,186		259		(11,449		)	7,863
Noncontrolling interest in subsidiary	—		—		4		—			4
Total liabilities and equity	$	12,520	$	24,371	$	1,133	$	(12,000	)	$	26,024

Condensed Consolidating Balance Sheet as of December 31, 2017

(Millions of Dollars)



	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,124	$	363	$	—	$	—		$	1,487
Restricted cash	59		—		—		—			59
Trade accounts receivable — net	4		578		—		—			582
Inventories	—		253		—		—			253
Commodity and other derivative contractual assets	—		190		—		—			190
Margin deposits related to commodity contracts	—		30		—		—			30
Prepaid expense and other current assets	—		72		—		—			72
Total current assets	1,187		1,486		—		—			2,673
Restricted cash	—		500		—		—			500
Investments	—		1,240		—		—			1,240
Investment in affiliated companies	5,632		—		—		(5,632		)	—
Property, plant and equipment — net	—		4,820		—		—			4,820
Goodwill	—		1,907		—		—			1,907
Identifiable intangible assets — net	—		2,530		—		—			2,530
Commodity and other derivative contractual assets	—		58		—		—			58
Accumulated deferred income taxes	5		705		—		—			710
Other noncurrent assets	6		156		—		—			162
Total assets	$	6,830	$	13,402	$	—	$	(5,632	)	$	14,600
LIABILITIES AND EQUITY
Current liabilities:
Long-term debt due currently	—		44		—		—			44
Trade accounts payable	11		462		—		—			473
Commodity and other derivative contractual liabilities	—		224		—		—			224
Margin deposits related to commodity contracts	—		4		—		—			4
Accrued taxes	58		—		—		—			58
Accrued taxes other than income	—		136		—		—			136
Accrued interest	—		16		—		—			16
Asset retirement obligations	—		99		—		—			99
Other current liabilities	86		211		—		—			297
Total current liabilities	155		1,196		—		—			1,351
Long-term debt, less amounts due currently	—		4,379		—		—			4,379
Commodity and other derivative contractual liabilities	—		102		—		—			102
Tax Receivable Agreement obligation	333		—		—		—			333
Asset retirement obligations	—		1,837		—		—			1,837
Identifiable intangible liabilities — net	—		36		—		—			36
Other noncurrent liabilities and deferred credits	—		220		—		—			220
Total liabilities	488		7,770		—		—			8,258
Total equity	6,342		5,632		—		(5,632		)	6,342
Total liabilities and equity	$	6,830	$	13,402	$	—	$	(5,632	)	$	14,600

Business And Significant Accounting Policies (Policies)	12 Months Ended
Business And Significant Accounting Policies (Policies)	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852). Fresh start reporting included (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring (TCEH, or the Predecessor) from the financial statements of the entity that emerges from restructuring (Vistra Energy, or the Successor), (2) accounting for the effects of the Plan of Reorganization, (3) assigning the reorganization value of the Successor entity by measuring all assets and liabilities of the Successor entity at fair value, and (4) selecting accounting policies for the Successor entity. The financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization and the related application of fresh start reporting. The reorganization value of Vistra Energy was assigned to its assets and liabilities in conformity with the procedures specified by FASB ASC 805, Business Combinations, and the portion of the reorganization value that was not attributable to identifiable tangible or intangible assets was recognized as goodwill. See Note 6 for further discussion of fresh start reporting. The 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 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 Predecessor Reorganization Items in Note 5 for further discussion of these accounting and reporting changes. The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our annual report on Form 10-K for the year ended December 31, 2017, with the exception of the changes in reportable segments as detailed above. 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. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. 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.
Derivative Instruments and Mark-to-Market Accounting	Derivative Instruments and Mark-to-Market Accounting We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities utilizing instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses. This recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that, beginning in January 2017, are legally characterized as settlement of derivative contracts rather than collateral. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 17 and 18 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. At December 31, 2018 and 2017, there were no derivative positions accounted for as cash flow or fair value hedges. For the Successor period, we report commodity hedging and trading results as revenue, fuel expense or purchased power in the statements of consolidated income (loss) depending on the type of activity. Electricity hedges, financial natural gas hedges and trading activities are primarily reported as revenue. Physical or financial hedges for coal, diesel or uranium, along with physical natural gas trades, are primarily reported as fuel expense. For the Predecessor periods, all activity was reported as a net gain (loss) from commodity hedging and trading activities. Realized and unrealized gains and losses associated with interest rate swap transactions are reported in the statements of consolidated income (loss) in interest expense for both the Predecessor and Successor.
Revenue Recognition	Revenue Recognition Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed. See Note 7 for detailed descriptions of revenue from contracts with customers. We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO or RTO, ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response available for system reliability requirements, and certain other electricity sales contracts. See Note 7 for detailed descriptions of revenue from contracts with customers. See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts.
Advertising Expense	Advertising Expense We expense advertising costs as incurred and include them within selling, general and administrative expenses. Advertising expenses totaled $46 million, $44 million, $9 million and $35 million for the Successor period for the year ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects.
Goodwill and Intangible Assets with Indefinite Lives	Goodwill and Intangible Assets with Indefinite Lives As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill (see Note 6). We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. The Predecessor's annual evaluation date was December 1
Nuclear Fuel	Nuclear Fuel Nuclear fuel is capitalized and reported as a component of our property, plant and equipment in our consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs and delivery fees in our statements of consolidated income (loss).
Major Maintenance Costs	Major Maintenance Costs Major maintenance costs incurred by the Successor during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in our statements of consolidated income (loss). The Predecessor charged all maintenance activities to expense as incurred.
Defined Benefit Plans and OPEB Plans	Defined Benefit Pension Plans and OPEB Plans On the Merger Date, Vistra Energy assumed the pension and OPEB plans that Dynegy had provided to certain of its eligible employees and retirees. The excess of the benefit obligations over the fair value of plan assets was recognized as a liability. See Note 2 for additional information regarding the Merger. On the Effective Date, EFH Corp. transferred sponsorship of certain employee benefit plans (including related assets), programs and policies to a subsidiary of Vistra Energy. Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employee from the company. Pension benefits are offered to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Effective January 1, 2017, the OPEB plan was amended to discontinue the life insurance benefits for active employees. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. Prior to the Effective Date, our Predecessor bore a portion of the costs of the EFH Corp. sponsored pension and OPEB plans and accounted for the arrangement under multiple employer plan accounting.
Stock-Based Compensation	Stock-Based Compensation Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. The fair value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model. Forfeitures are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award.
Sales And Excise Taxes	Sales and Excise Taxes Sales and excise taxes are accounted for as "pass through" items on the consolidated balance sheets with no effect on the statements of consolidated income (loss) (i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction).
Franchise And Revenue-Based Taxes	Franchise and Revenue-Based Taxes Unlike sales and excise taxes, franchise and gross receipt taxes are not a "pass through" item. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in our statements of consolidated income (loss).
Income Taxes	Income Taxes On the Merger Date, Vistra Energy and Dynegy effected a merger transaction that for tax purposes was treated as a tax-free reorganization in which Vistra Energy survived as the parent entity. In general, all of Dynegy's tax basis and attributes were transferred to Vistra Energy, including approximately $4.2 billion of utilizable NOLs and refundable AMT tax credits. Prior to the Effective Date, EFH Corp. filed a consolidated U.S. federal income tax return that included the results of our Predecessor; however, our Predecessor's income tax expense and related balance sheet amounts were recorded as if it filed separate corporate income tax returns. Investment tax credits are accounted for under the deferral method, which resulted in a reduction to the basis of the Upton 2 solar facility of $78 million and a corresponding increase in the deferred tax assets in 2018. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules. See Note 9. We report interest and penalties related to uncertain tax positions as current income tax expense.
Tax Receivable Agreement	Tax Receivable Agreement The Company accounts for its obligations under the Tax Receivable Agreement (TRA) as a liability in our consolidated balance sheets (see Note 10). The carrying value of the TRA obligation represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate and (b) estimates of our taxable income in the current and future years. Our taxable income takes into consideration the current federal tax code and reflects our current estimates of future results of the business. The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method and the interest rate estimated at the Emergence Date. Changes in the estimated amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and are included on our statement of consolidated income (loss) under the heading of Impacts of Tax Receivable Agreement.
Accounting for Contingencies	Accounting for Contingencies Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered cash equivalents.
Restricted Cash	Restricted Cash The terms of certain agreements require the restriction of cash for specific purposes.
Property, Plant and Equipment	Property, Plant and Equipment In connection with fresh start reporting, carrying amounts of property, plant and equipment were adjusted to estimated fair values as of the Effective Date (see Note 6). Property, plant and equipment added subsequent to the Effective Date has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed (see Notes 2 and 3). Significant improvements or additions to our property, plant and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 11. Depreciation of our property, plant and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives.
Asset Retirement Obligations	Asset Retirement Obligations (ARO) A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or for which capitalized costs are not recoverable are reflected in the statements of consolidated income (loss).
Inventories	Inventories Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (on a weighted average basis) or market. We expect to recover the value of inventory costs in the normal course of business.
Investments	Investments Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 23 for discussion of these and other investments. Unconsolidated Investments We use the equity method of accounting for investments in affiliates over which we exercise significant influence. Our share of net income (loss) from these affiliates is recorded to equity in earnings (loss) of unconsolidated investment in the statements of consolidated net income (loss).
Noncontrolling Interest	Noncontrolling Interest Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own. EEI is our consolidated subsidiary that owns a coal facility in Joppa, Illinois. This noncontrolling interest is classified as a component of equity separate from stockholders' equity in the consolidated balance sheets.
Treasury Stock	Treasury Stock Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capital.

Business And Significant Accounting Policies (Tables) (Tables)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Adoption of New Accounting Standards

As of January 1, 2018, the cumulative effect of the changes made to our consolidated balance sheet for the adoption of the new revenue standard was as follows:



	December 31, 2017			Adoption of New Revenue Standard			January 1, 2018
Impact on consolidated balance sheet:
Assets
Prepaid expense and other current assets	$	72		$	5		$	77
Accumulated deferred income taxes	$	710		$	(4	)	$	706
Other noncurrent assets	$	162		$	16		$	178
Equity
Retained deficit	$	(1,410	)	$	17		$	(1,393	)

The disclosure of the impact of adoption on our statement of consolidated income (loss) and consolidated balance sheet was as follows:



	Year Ended December 31, 2018
	As Reported			Amount Without Adoption of New Revenue Standard			Effect of Change Higher (Lower)
Impact on statement of consolidated income (loss):
Operating revenues	$	9,144		$	9,141		$	3
Selling, general and administrative expenses	(926		)	(939		)	13
Net income (loss)	(56		)	(68		)	12



	December 31, 2018
	As Reported			Balances Without Adoption of New Revenue Standard			Effect of Change Higher (Lower)
Impact on consolidated balance sheet:
Assets
Prepaid expense and other current assets	$	152		$	145		$	7
Accumulated deferred income taxes	1,336			1,349			(13		)
Other noncurrent assets	590			559			31
Equity
Retained deficit	$	(1,449	)	$	(1,478	)	$	29

Merger Transaction and Business Combination Accounting (Tables)

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Schedule of recognized identified assets acquired and liabilities assumed

The following table summarizes the consideration paid and the preliminary allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Merger as of the Merger Date. Based on the opening price of Vistra Energy common stock on the Merger Date, the purchase price was approximately $2.3 billion. The preliminary values included below represent our current best estimates for property plant and equipment, identifiable intangible assets and liabilities, goodwill, inventories, asset retirement obligations, contingent liabilities and deferred taxes. During the year ended December 31, 2018, we updated the initial purchase price allocation reported as of June 30, 2018 with revised valuation estimates by increasing property, plant and equipment by $158 million, decreasing intangible assets by $36 million, increasing goodwill by $161 million, decreasing accounts receivable, inventory, prepaid expenses and other current assets by $7 million, increasing accumulated deferred tax asset by $101 million, decreasing other noncurrent assets by $109 million, increasing trade accounts payable and other current liabilities by $43 million, increasing other noncurrent liabilities by $172 million, increasing asset retirement obligations, including amounts due currently by $58 million as well as other minor adjustments. The valuation revisions were a result of updated inputs used in determining the fair value of the acquired assets and liabilities. The purchase price allocation is substantially complete, but is dependent upon final valuation determinations, which may materially change from our current estimates. Goodwill is currently recorded at the corporate and other non-segment operations pending the final valuation determinations. We currently expect the final purchase price allocation will be completed no later than the first quarter of 2019 and goodwill will be allocated to the related reporting units at that time.



Dynegy shares outstanding as of April 9, 2018 (in millions)	144.8
Exchange Ratio	0.652
Vistra Energy shares issued for Dynegy shares outstanding (in millions)	94.4
Opening price of Vistra Energy common stock on April 9, 2018	$	19.87
Purchase price for common stock	$	1,876
Fair value of equity component of tangible equity units	$	369
Fair value of outstanding stock compensation awards attributable to pre-combination service	$	26
Fair value of outstanding warrants	$	2
Total purchase price	$	2,273



Preliminary Purchase Price Allocation
Cash and cash equivalents	$	445
Trade accounts receivables, inventories, prepaid expenses and other current assets	856
Property, plant and equipment	10,520
Accumulated deferred income taxes	492
Identifiable intangible assets	351
Goodwill	161
Other noncurrent assets	423
Total assets acquired	13,248
Trade accounts payable and other current liabilities	687
Commodity and other derivative contractual assets and liabilities, net	422
Asset retirement obligations, including amounts due currently	477
Long-term debt, including amounts due currently	8,920
Other noncurrent liabilities	464
Total liabilities assumed	10,970
Identifiable net assets acquired	2,278
Noncontrolling interest in subsidiary	5
Total purchase price	$	2,273

The following table summarizes the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed.



Cash paid to seller at close	$	603
Net working capital adjustments	(4		)
Consideration paid to seller	599
Cash paid to repay project financing at close	950
Total cash paid related to acquisition	$	1,549
Cash and cash equivalents	$	210
Property, plant and equipment — net	1,316
Commodity and other derivative contractual assets	47
Other assets	44
Total assets acquired	1,617
Commodity and other derivative contractual liabilities	53
Trade accounts payable and other liabilities	15
Total liabilities assumed	68
Identifiable net assets acquired	$	1,549

The Lamar and Forney Acquisition did not result in the recording of goodwill since the purchase price did not exceed the fair value of the net assets acquired.

The following table summarizes the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed.



Cash paid to seller at close	$	603
Net working capital adjustments	(4		)
Consideration paid to seller	599
Cash paid to repay project financing at close	950
Total cash paid related to acquisition	$	1,549
Cash and cash equivalents	$	210
Property, plant and equipment — net	1,316
Commodity and other derivative contractual assets	47
Other assets	44
Total assets acquired	1,617
Commodity and other derivative contractual liabilities	53
Trade accounts payable and other liabilities	15
Total liabilities assumed	68
Identifiable net assets acquired	$	1,549

Pro forma financial information

Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the year ended December 31, 2018 and 2017 assumes that the Merger occurred on January 1, 2017. 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 Merger been completed on January 1, 2017, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.



	Year Ended December 31,
	2018			2017
Revenues	$	10,595		$	10,509
Net loss	$	(268	)	$	(969	)
Net loss attributable to Vistra Energy	$	(265	)	$	(983	)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — basic	$	(0.52	)	$	(1.83	)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — diluted	$	(0.52	)	$	(1.83	)

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Merger, effects of the Merger on tax expense (benefit), changes in the expected impacts of the tax receivable agreement due to the Merger, and other related adjustments.

The following unaudited pro forma financial information for the Predecessor period from January 1, 2016 through October 2, 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
	Period from January 1, 2016 through October 2, 2016
Revenues	$	4,116
Net income (loss)	$	22,835

Acquisition and Development of Generation Facilities (Tables)

12 Months Ended

Dec. 31, 2018

Acquisition And Development Of Generation Facilities [Abstract]

Schedule of recognized identified assets acquired and liabilities assumed

The following table summarizes the consideration paid and the preliminary allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Merger as of the Merger Date. Based on the opening price of Vistra Energy common stock on the Merger Date, the purchase price was approximately $2.3 billion. The preliminary values included below represent our current best estimates for property plant and equipment, identifiable intangible assets and liabilities, goodwill, inventories, asset retirement obligations, contingent liabilities and deferred taxes. During the year ended December 31, 2018, we updated the initial purchase price allocation reported as of June 30, 2018 with revised valuation estimates by increasing property, plant and equipment by $158 million, decreasing intangible assets by $36 million, increasing goodwill by $161 million, decreasing accounts receivable, inventory, prepaid expenses and other current assets by $7 million, increasing accumulated deferred tax asset by $101 million, decreasing other noncurrent assets by $109 million, increasing trade accounts payable and other current liabilities by $43 million, increasing other noncurrent liabilities by $172 million, increasing asset retirement obligations, including amounts due currently by $58 million as well as other minor adjustments. The valuation revisions were a result of updated inputs used in determining the fair value of the acquired assets and liabilities. The purchase price allocation is substantially complete, but is dependent upon final valuation determinations, which may materially change from our current estimates. Goodwill is currently recorded at the corporate and other non-segment operations pending the final valuation determinations. We currently expect the final purchase price allocation will be completed no later than the first quarter of 2019 and goodwill will be allocated to the related reporting units at that time.



Dynegy shares outstanding as of April 9, 2018 (in millions)	144.8
Exchange Ratio	0.652
Vistra Energy shares issued for Dynegy shares outstanding (in millions)	94.4
Opening price of Vistra Energy common stock on April 9, 2018	$	19.87
Purchase price for common stock	$	1,876
Fair value of equity component of tangible equity units	$	369
Fair value of outstanding stock compensation awards attributable to pre-combination service	$	26
Fair value of outstanding warrants	$	2
Total purchase price	$	2,273



Preliminary Purchase Price Allocation
Cash and cash equivalents	$	445
Trade accounts receivables, inventories, prepaid expenses and other current assets	856
Property, plant and equipment	10,520
Accumulated deferred income taxes	492
Identifiable intangible assets	351
Goodwill	161
Other noncurrent assets	423
Total assets acquired	13,248
Trade accounts payable and other current liabilities	687
Commodity and other derivative contractual assets and liabilities, net	422
Asset retirement obligations, including amounts due currently	477
Long-term debt, including amounts due currently	8,920
Other noncurrent liabilities	464
Total liabilities assumed	10,970
Identifiable net assets acquired	2,278
Noncontrolling interest in subsidiary	5
Total purchase price	$	2,273

The following table summarizes the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed.



Cash paid to seller at close	$	603
Net working capital adjustments	(4		)
Consideration paid to seller	599
Cash paid to repay project financing at close	950
Total cash paid related to acquisition	$	1,549
Cash and cash equivalents	$	210
Property, plant and equipment — net	1,316
Commodity and other derivative contractual assets	47
Other assets	44
Total assets acquired	1,617
Commodity and other derivative contractual liabilities	53
Trade accounts payable and other liabilities	15
Total liabilities assumed	68
Identifiable net assets acquired	$	1,549

The Lamar and Forney Acquisition did not result in the recording of goodwill since the purchase price did not exceed the fair value of the net assets acquired.

The following table summarizes the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed.



Cash paid to seller at close	$	603
Net working capital adjustments	(4		)
Consideration paid to seller	599
Cash paid to repay project financing at close	950
Total cash paid related to acquisition	$	1,549
Cash and cash equivalents	$	210
Property, plant and equipment — net	1,316
Commodity and other derivative contractual assets	47
Other assets	44
Total assets acquired	1,617
Commodity and other derivative contractual liabilities	53
Trade accounts payable and other liabilities	15
Total liabilities assumed	68
Identifiable net assets acquired	$	1,549

Pro forma financial information

Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the year ended December 31, 2018 and 2017 assumes that the Merger occurred on January 1, 2017. 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 Merger been completed on January 1, 2017, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.



	Year Ended December 31,
	2018			2017
Revenues	$	10,595		$	10,509
Net loss	$	(268	)	$	(969	)
Net loss attributable to Vistra Energy	$	(265	)	$	(983	)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — basic	$	(0.52	)	$	(1.83	)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — diluted	$	(0.52	)	$	(1.83	)

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Merger, effects of the Merger on tax expense (benefit), changes in the expected impacts of the tax receivable agreement due to the Merger, and other related adjustments.

The following unaudited pro forma financial information for the Predecessor period from January 1, 2016 through October 2, 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
	Period from January 1, 2016 through October 2, 2016
Revenues	$	4,116
Net income (loss)	$	22,835

Disposition of Generation Facilities (Tables)

12 Months Ended

Dec. 31, 2018

Retirement of Generation Facilities [Abstract]

Retirements Of Generation Capacity [Table Text Block]

Two of our non-operated, jointly held power plants acquired in the Merger, for which our proportional generation capacity was 883 MW, were retired in May 2018. These units were retired as previously scheduled. No gain or loss was recorded in conjunction with the retirement of these units, and the operational results of these facilities are included in our Asset Closure segment. The following table details the units retired.



Name	Location	Fuel Type	Net Generation Capacity (MW)	Ownership Interest	Date Units Taken Offline
Killen	Manchester, Ohio	Coal	204	33%	May 31, 2018
Stuart	Aberdeen, Ohio	Coal	679	39%	May 24, 2018
Total			883

In January and February 2018, we retired three power plants with a total installed nameplate generation capacity of 4,167 MW. We decided to retire these units because they were projected to be uneconomic based on then current market conditions and would have faced significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement. Expected retirement expenses were accrued in the third and fourth quarter 2017 and, as a result, no retirement expenses were recorded related to these facilities in the year ended December 31, 2018. The operational results of these facilities are included in our Asset Closure segment. The following table details the units retired.



Name	Location (all in the state of Texas)	Fuel Type	Installed Nameplate Generation Capacity (MW)	Number of Units	Date Units Taken Offline
Monticello	Titus County	Lignite/Coal	1,880	3	January 4, 2018
Sandow	Milam County	Lignite	1,137	2	January 11, 2018
Big Brown	Freestone County	Lignite/Coal	1,150	2	February 12, 2018
Total			4,167	7

Emergence From Chapter 11 Cases (Tables)

12 Months Ended

Dec. 31, 2018

Reorganization Items

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the 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 Predecessor period from January 1, 2016 through October 2, 2016 as reported in the statements of consolidated income (loss):



	Predecessor
	Period from January 1, 2016 through October 2, 2016
Gain on reorganization adjustments (Note 6)	$	(24,252	)
Loss from the adoption of fresh start reporting	2,013
Expenses related to legal advisory and representation services	55
Expenses related to other professional consulting and advisory services	39
Contract claims adjustments	13
Other	11
Total reorganization items	$	(22,121	)

Fresh-Start Reporting (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of reorganization value of assets estimate

Under ASC 852, reorganization value is generally allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill. Vistra Energy estimates its reorganization value of assets at approximately $15.161 billion as of October 3, 2016, which consists of the following:



Business enterprise value	$	10,500
Cash excluded from business enterprise value	1,594
Deferred asset related to prepaid capital lease obligation	38
Current liabilities, excluding short-term portion of debt and capital leases	1,123
Noncurrent, non-interest bearing liabilities	1,906
Vistra Energy reorganization value of assets	$	15,161

Schedule of adjustments to balance sheet including impact of plan of reorganization and fresh-start reporting

The adjustments to TCEH's October 3, 2016 consolidated balance sheet below include the impacts of the Plan of Reorganization and the adoption of fresh start reporting.



	October 3, 2016
	TCEH (Predecessor) (1)		Reorganization Adjustments (2)				Fresh Start Adjustments				Vistra Energy (Successor)
ASSETS
Current assets:
Cash and cash equivalents	$	1,829	$	(1,028	)	(3)	$	—			$	801
Restricted cash	12		131			(4)	—				143
Trade accounts receivable — net	750		4				—				754
Advances to parents and affiliates of Predecessor	78		(78		)		—				—
Inventories	374		—				(86		)	(17)	288
Commodity and other derivative contractual assets	255		—				—				255
Margin deposits related to commodity contracts	42		—				—				42
Other current assets	47		17				3				67
Total current assets	3,387		(954		)		(83		)		2,350
Restricted cash	650		—				—				650
Advance to parent and affiliates of Predecessor	17		(21		)		4				—
Investments	1,038		1				9			(18)	1,048
Property, plant and equipment — net	10,359		53				(5,970		)	(19)	4,442
Goodwill	152		—				1,755			(27)	1,907
Identifiable intangible assets — net	1,148		4				2,256			(20)	3,408
Commodity and other derivative contractual assets	73		—				(14		)		59
Deferred income taxes	—		320			(5)	730			(21)	1,050
Other noncurrent assets	51		38				158			(22)	247
Total assets	$	16,875	$	(559	)		$	(1,155	)		$	15,161
LIABILITIES AND EQUITY
Current liabilities:
Long-term debt due currently	$	4	$	5			$	(1	)		$	8
Trade accounts payable	402		145			(6)	3				550
Trade accounts and other payables to affiliates of Predecessor	152		(152		)	(6)	—				—
Commodity and other derivative contractual liabilities	125		—				—				125
Margin deposits related to commodity contracts	64		—				—				64
Accrued income taxes	12		12				—				24
Accrued taxes other than income	119		4				—				123
Accrued interest	110		(109		)	(7)	—				1
Other current liabilities	243		170			(8)	5				418
Total current liabilities	1,231		75				7				1,313



	October 3, 2016
	TCEH (Predecessor) (1)			Reorganization Adjustments (2)				Fresh Start Adjustments				Vistra Energy (Successor)
Long-term debt, less amounts due currently	—			3,476			(9)	151			(23)	3,627
Borrowings under debtor-in-possession credit facilities	3,387			(3,387		)	(9)	—				—
Liabilities subject to compromise	33,749			(33,749		)	(10)	—				—
Commodity and other derivative contractual liabilities	5			—				3				8
Deferred income taxes	256			(256		)	(11)	—				—
Tax Receivable Agreement obligation	—			574			(12)	—				574
Asset retirement obligations	809			—				854			(24)	1,663
Other noncurrent liabilities and deferred credits	1,018			117			(13)	(900		)	(25)	235
Total liabilities	40,455			(33,150		)		115				7,420
Equity:
Common stock	—			4			(14)	—				4
Additional paid-in-capital	—			7,737			(15)	—				7,737
Accumulated other comprehensive income (loss)	(32		)	22				10			(26)	—
Predecessor membership interests	(23,548		)	24,828			(16)	(1,280		)	(26)	—
Total equity	(23,580		)	32,591				(1,270		)		7,741
Total liabilities and equity	$	16,875		$	(559	)		$	(1,155	)		$	15,161


(1)	Represents the consolidated balance sheet of TCEH as of October 3, 2016.

Schedule of plan of reorganization adjustments to cash and cash equivalents

Net adjustments to cash, which represent distributions made or funding provided to an escrow account, classified as restricted cash, under the Plan of Reorganization, as follows:



Sources (uses):
Net proceeds from PrefCo preferred stock sale	$	69
Addition of cash balances from the Contributed EFH Debtors	22
Payments to TCEH first lien creditors, including adequate protection	(486		)
Payment to TCEH unsecured creditors (including $73 million to escrow)	(502		)
Payment of administrative claims to TCEH creditors	(53		)
Payment of legal fees, professional fees and other costs (including $52 million to escrow)	(78		)
Net use of cash	$	(1,028	)

Schedule of plan of reorganization adjustments to liabilities subject to compromise

Reflects the elimination of TCEH's liabilities subject to compromise pursuant to the Plan of Reorganization (see Note 5). Liabilities subject to compromise were settled as follows in accordance with the Plan of Reorganization:



Notes, loans and other debt	$	31,668
Accrued interest on notes, loans and other debt	646
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements	1,243
Trade accounts payable and other expected allowed claims	192
Third-party liabilities subject to compromise	33,749
LSTC from the Contributed EFH Entities	8
Total liabilities subject to compromise	33,757
Fair value of equity issued to TCEH first lien creditors	(7,741		)
TRA Rights issued to TCEH first lien creditors	(574		)
Cash distributed and accruals for TCEH first lien creditors	(377		)
Cash distributed for TCEH unsecured claims	(502		)
Cash distributed and accruals for TCEH administrative claims	(60		)
Settlement of affiliate balances	(99		)
Net liabilities of contributed entities and other items	(60		)
Gain on extinguishment of LSTC	$	24,344

Schedule of plan of reorganization adjustments to equity

Reflects adjustments to present Vistra Energy equity value at approximately $7.741 billion based on a reconciliation from the $10.5 billion enterprise value described above under Reorganization Value as depicted below:



Enterprise value	$	10,500
Vistra Operations Credit Facility – Initial Term Loan B Facility	(2,871		)
Vistra Operations Credit Facility – Term Loan C Facility	(655		)
Accrual for post-Emergence claims satisfaction	(181		)
Tax Receivable Agreement obligation	(574		)
Preferred stock of PrefCo	(70		)
Other items	(2		)
Cash and cash equivalents	801
Restricted cash	793
Equity value at Emergence	$	7,741
Common stock at par value	$	4
Additional paid-in capital	7,737
Equity value	$	7,741
Shares outstanding at October 3, 2016 (in millions)	427.5
Per share value	$	18.11

Schedule of plan of reorganization adjustments to Membership Interests

Membership Interest impact of Plan of Reorganization are shown below:



Gain on extinguishment of LSTC	$	24,344
Elimination of accumulated other comprehensive income	(22		)
Change in control payments	(23		)
Professional fees	(33		)
Other items	(14		)
Pretax gain on reorganization adjustments (Note 5)	24,252
Deferred tax impact of the Plan of Reorganization and Spin-off	576
Total impact to membership interests	$	24,828

Schedule of fresh-start adjustments to property, plant and equipment

Reflects the change in fair value of property, plant and equipment related primarily to generation and mining assets as detailed below:



Property, Plant and Equipment	Adjustment			Fair Value
Generation plants and mining assets	$	(6,057	)	$	3,698
Land	140			490
Nuclear Fuel	(23		)	157
Other equipment	(30		)	97
Total	$	(5,970	)	$	4,442

Schedule of fresh-start adjustments to goodwill

Reflects increase in goodwill balance to present final goodwill as the reorganization value in excess of the identifiable tangible assets, intangible assets, and liabilities at Emergence.



Business enterprise value	$	10,500
Add: Fair value of liabilities excluded from enterprise value	3,030
Less: Fair value of tangible assets	(8,215		)
Less: Fair value of identified intangible assets	(3,408		)
Vistra Energy goodwill	$	1,907

Revenue (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

The following tables disaggregate our revenue by major source:



	Year Ended December 31, 2018
	Retail			ERCOT			PJM			NY/NE			MISO			Asset Closure			CAISO/Eliminations			Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	4,426		$	—		$	—		$	—		$	—		$	—		$	—		$	4,426
Retail energy charge in Northeast/Midwest	1,123			—			—			—			—			—			—			1,123
Wholesale generation revenue from ISO/RTO	—			1,151			792			544			420			52			167			3,126
Capacity revenue	—			—			369			240			53			6			30			698
Revenue from other wholesale contracts	—			214			29			42			133			—			6			424
Total revenue from contracts with customers	5,549			1,365			1,190			826			606			58			203			9,797
Other revenues:
Intangible amortization	(26		)	(1		)	2			(9		)	(9		)	—			—			(43		)
Hedging and other revenues (a)	74			(362		)	(62		)	(41		)	(195		)	(31		)	7			(610		)
Affiliate sales	—			1,632			595			41			318			23			(2,609		)	—
Total other revenues	48			1,269			535			(9		)	114			(8		)	(2,602		)	(653		)
Total revenues	$	5,597		$	2,634		$	1,725		$	817		$	720		$	50		$	(2,399	)	$	9,144

____________


(a)	Includes $380 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 22 for unrealized net gains (losses) by segment.

Accounts Receivable, Contracts With Customers [Table Text Block]

The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts with customers and other activities:



	December 31, 2018
Trade accounts receivable from contracts with customers — net	$	951
Other trade accounts receivable — net	136
Total trade accounts receivable — net	$	1,087

Goodwill And Identifiable Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of identifiable intangible assets reported in balance sheet

Identifiable intangible assets are comprised of the following:



	December 31, 2018						December 31, 2017
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	1,680	$	876	$	804	$	1,648	$	572	$	1,076
Software and other technology-related assets	270		105		165		183		47		136
Retail and wholesale contracts	316		138		178		154		87		67
Contractual service agreements	70		—		70		—		—		—
Other identifiable intangible assets (a)	42		15		27		33		11		22
Total identifiable intangible assets subject to amortization	$	2,378	$	1,134	1,244		$	2,018	$	717	1,301
Retail trade names (not subject to amortization)					1,245						1,225
Mineral interests (not currently subject to amortization)					4						4
Total identifiable intangible assets					$	2,493					$	2,530

Schedule of identifiable intangible liabilities reported in balance sheet

Identifiable intangible liabilities are comprised of the following:



	Year Ended December 31,
	2018		2017
Identifiable Intangible Liability
Contractual service agreements	$	136	$	—
Purchase and sale contracts	195		36
Environmental allowances	$	70	$	—
Total identifiable intangible liabilities	$	401	$	36

Schedule of amortization expense related to intangible assets and liabilities (including income statement line item)

Amortization expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the statements of consolidated income (loss)) consisted of:



			Successor						Predecessor
Identifiable Intangible Assets and Liabilities	Statements of Consolidated Income (Loss) Line	Remaining useful lives of identifiable intangible assets at December 31, 2018 (weighted average in years)	Year Ended December 31,				Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Identifiable Intangible Assets and Liabilities	Statements of Consolidated Income (Loss) Line		2018		2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Retail customer relationship	Depreciation and amortization	4	$	304	$	420	$	152	$	9
Software and other technology-related assets	Depreciation and amortization	3	62		38		9		44
Retail and wholesale contracts/purchase and sale contracts	Operating revenues/fuel, purchased power costs and delivery fees	4	43		59		38		—
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	4	58		15		4		6
Total amortization expense (a)			$	467	$	532	$	203	$	59

____________


(a)	Amounts recorded in depreciation and amortization totaled $370 million, $463 million, $162 million and $58 million for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.

Schedule of estimated amortization expense of identifiable intangible assets

As of December 31, 2018, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2019	$	299
2020	$	201
2021	$	154
2022	$	91
2023	$	67

As of December 31, 2018, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2019	$	299
2020	$	201
2021	$	154
2022	$	91
2023	$	67

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of components of income tax expense (benefit)

The components of our income tax expense (benefit) are as follows:



	Successor								Predecessor
	Year Ended December 31,					Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017		Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Current:
U.S. Federal	$	(13	)	$	72	$	—		$	(6	)
State	30			14		6			9
Total current	17			86		6			3
Deferred:
U.S. Federal	(8		)	417		(75		)	(1,234		)
State	(54		)	1		(1		)	(36		)
Total deferred	(62		)	418		(76		)	(1,270		)
Total	$	(45	)	$	504	$	(70	)	$	(1,267	)

Schedule of reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded

Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded:



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Income (loss) before income taxes	$	(101	)	$	250		$	(233	)	$	21,584
US federal statutory rate	21		%	35		%	35		%	35		%
Income taxes at the U.S. federal statutory rate	(20		)	88			(82		)	7,554
Nondeductible TRA accretion	8			(80		)	5			—
State tax, net of federal benefit	22			13			3			(21		)
Impacts of tax reform legislation on deferred taxes	—			451			—			—
Return to provision adjustment	(12		)	19			—			—
Remeasurement of historical Vistra Energy deferred taxes for expanded state footprint	(54		)	—			—			—
Effect of refundable minimum tax credits no longer subject to sequestration	(15		)	—			—			—
Nondeductible compensation	8			—			—			—
Nondeductible transaction costs	3			—			—			—
Equity awards	(3		)	—			—			—
Nondeductible debt restructuring costs	—			—			2			38
Nondeductible interest expense	—			—			—			12
Nontaxable gain on extinguishment of LSTC	—			—			—			(8,593		)
Valuation allowance on state NOLs	20			—			—			(210		)
Other	(2		)	13			2			(47		)
Income tax expense (benefit)	$	(45	)	$	504		$	(70	)	$	(1,267	)
Effective tax rate	44.6		%	201.6		%	30.0		%	(5.9		)%

Schedule of deferred tax assets and liabilities

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2018 and 2017 are as follows:



	December 31,
	2018		2017
Noncurrent Deferred Income Tax Assets
Tax credit carryforwards	$	76	$	—
Loss carryforwards	958		—
Property, plant and equipment	—		520
Identifiable intangible assets	184		81
Long-term debt	188		20
Employee benefit obligations	109		56
Commodity contracts and interest rate swaps	212		25
Other	40		8
Total deferred tax assets	$	1,767	$	710
Noncurrent Deferred Income Tax Liabilities
Property, plant and equipment	406		—
Total deferred tax liabilities	406		—
Valuation allowance	35		—
Net Deferred Income Tax Asset	$	1,326	$	710

Schedule of income tax contingencies

The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets, during the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016:



	Successor						Predecessor
	Year Ended December 31,				Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
	2018		2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Balance at beginning of period, excluding interest and penalties	$	—	$	—	$	—	$	36
Additions allocated in the Merger	39		—		—		—
Reductions based on tax positions related to prior years	—		—		—		(1		)
Settlements with taxing authorities	—		—		—		(35		)
Balance at end of period, excluding interest and penalties	$	39	$	—	$	—	$	—

Tax Receivable Agreement Obligation (Tables)

12 Months Ended

Dec. 31, 2018

Tax Receivable Agreement Obligation

The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016:



	Successor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016
TRA obligation at the beginning of the period	$	357		$	596		$	574
Accretion expense	65			82			22
Payments	(16		)	(26		)	—
Changes in tax assumptions impacting timing of payments	14			(62		)	—
Revaluation due to tax reform legislation	—			(233		)	—
TRA obligation at the end of the period	420			357			596
Less amounts due currently	—			(24		)	—
Noncurrent TRA obligation at the end of the period	$	420		$	333		$	596

Interest Expense and Related Charges (Tables)

12 Months Ended

Dec. 31, 2018

Interest Expense and Related Charges [Abstract]

Schedule of Interest Expense and Related Charges



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Interest paid/accrued post-Emergence	$	537		$	213		$	51		$	—
Interest paid/accrued on debtor-in-possession financing	—			—			—			76
Adequate protection amounts paid/accrued	—			—			—			977
Unrealized mark-to-market net (gains) losses on interest rate swaps	5			(29		)	11			—
Amortization of debt issuance costs, discounts and premiums	—			4			(1		)	4
Debt extinguishment loss	27			—			—			—
Capitalized interest	(12		)	(7		)	(3		)	(9		)
Other	15			12			2			1
Total interest expense and related charges	$	572		$	193		$	60		$	1,049

Contractual Interest Expense On Pre-Petition Liabilities]



	Predecessor
	Period from January 1, 2016 through October 2, 2016
Contractual interest on debt classified as LSTC	$	1,570
Adequate protection amounts paid/accrued	930
Contractual interest on debt classified as LSTC not paid/accrued	$	640

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

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.



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Net loss attributable to common stock — basic (a)	$	(54	)	$	(254	)	$	(163	)
Weighted average shares of common stock outstanding — basic	504,954,371			427,761,460			427,560,620
Net loss per weighted average share of common stock outstanding — basic	$	(0.11	)	$	(0.59	)	$	(0.38	)
Weighted average shares of common stock outstanding — diluted	504,954,371			427,761,460			427,560,620
Net loss per weighted average share of common stock outstanding — diluted	$	(0.11	)	$	(0.59	)	$	(0.38	)

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2018

Debtor-In-Possession Obligations [Abstract]

Schedule of Long-term Debt Instruments

Amounts in the table below represent the categories of long-term debt obligations incurred by the Successor.



	December 31,
	2018			2017
Vistra Operations Credit Facilities	$	5,813		$	4,311
Vistra Operations 5.500% Senior Notes, due September 1, 2026	1,000			—
Vistra Energy Senior Notes:
7.375% Senior Notes, due November 1, 2022	1,707			—
5.875% Senior Notes, due June 1, 2023	500			—
7.625% Senior Notes, due November 1, 2024	1,147			—
8.034% Senior Notes, due February 2, 2024	25			—
8.000% Senior Notes, due January 15, 2025	81			—
8.125% Senior Notes, due January 30, 2026	166			—
Total Vistra Energy Senior Notes	3,626			—
Other:
7.000% Amortizing Notes, due July 1, 2019	24			—
Forward Capacity Agreements	236			—
Equipment Financing Agreements	120			—
Mandatorily redeemable subsidiary preferred stock (a)	70			70
8.82% Building Financing due semiannually through February 11, 2022 (b)	21			27
Total other long-term debt	471			97
Unamortized debt premiums, discounts and issuance costs (c)	155			15
Total long-term debt including amounts due currently	11,065			4,423
Less amounts due currently	(191		)	(44		)
Total long-term debt less amounts due currently	$	10,874		$	4,379

____________


(a)	Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note 5). This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance.


(b)	Obligation related to a corporate office space capital lease transferred to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our consolidated balance sheets.

Schedule of Line of Credit Facilities

The Vistra Operations Credit Facilities and related available capacity at December 31, 2018 are presented below.



		December 31, 2018
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity
Revolving Credit Facility (a)	June 14, 2023	$	2,500	$	—	$	1,135
Term Loan B-1 Facility	August 4, 2023	2,793		2,793		—
Term Loan B-2 Facility	December 14, 2023	980		980		—
Term Loan B-3 Facility	December 31, 2025	2,040		2,040		—
Total Vistra Operations Credit Facilities		$	8,313	$	5,813	$	1,135

___________


(a)	Facility to be used for general corporate purposes. Facility includes a $2.3 billion letter of credit sub-facility, of which $1.365 billion of letters of credit were outstanding at December 31, 2018 and which reduce our available capacity.

Schedule of Maturities of Long-term Debt

Maturities — Long-term debt maturities at December 31, 2018 are as follows:



	December 31, 2018
2019	$	191
2020	205
2021	129
2022	1,782
2023	4,150
Thereafter	4,453
Unamortized premiums, discounts and debt issuance costs	155
Total long-term debt, including amounts due currently	$	11,065

Commitments and Contingencies Disclosure [Abstract]

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

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Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Commitments And Contingencies Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of contractual commitments under energy-related contracts, leases and other agreements [Table Text Block]

At December 31, 2018, we had contractual commitments under long-term service and maintenance contracts, energy-related contracts, leases and other agreements as follows.



	Long-Term Service and Maintenance Contracts		Coal purchase and transportation agreements		Pipeline transportation and storage reservation fees		Nuclear Fuel Contracts		Other Contracts
2019	$	175	$	765	$	101	$	69	$	101
2020	181		227		95		71		74
2021	135		118		72		58		20
2022	183		103		48		38		13
2023	133		64		35		46		9
Thereafter	2,619		186		145		155		68
Total	$	3,426	$	1,463	$	496	$	437	$	285

Schedule of future minimum lease payments for capital and operating leases

At December 31, 2018, future minimum lease payments under operating leases are as follows:



	Operating Leases (a)
2019	$	35
2020	29
2021	25
2022	20
2023	19
Thereafter	168
Total future minimum lease payments	$	296

___________


(a)	Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.

Equity (Tables)

12 Months Ended

Dec. 31, 2018

Stockholders' Equity Note [Abstract]

Schedule of common stock outstanding

Equity Issuances and Repurchases — Changes in the number of shares of common stock outstanding for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 are reflected in the table below.



	Successor
	Year Ended December 31, 2018		Year Ended December 31, 2017	Period from October 3, 2016 through December 31, 2016
Shares outstanding at beginning of period	428,398,802		427,580,232	—
Shares issued (a)	97,639,105		818,570	427,580,232
Shares retired	(6,815	)	—	—
Shares repurchased (b)	(32,815,783	)	—	—
Shares outstanding at end of period	493,215,309		428,398,802	427,580,232

____________


(a)	Includes share awards granted to nonemployee directors.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Schedule of assets and liabilities measured at fair value on a recurring basis



December 31, 2018
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	456	$	152	$	153	$	1	$	762
Interest rate swaps	—		77		—		—		77
Nuclear decommissioning trust – equity securities (c)	449		—		—		—		449
Nuclear decommissioning trust – debt securities (c)	—		443		—		—		443
Sub-total	$	905	$	672	$	153	$	1	1,731
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									278
Total assets									$	2,009
Liabilities:
Commodity contracts	$	557	$	766	$	288	$	1	$	1,612
Interest rate swaps	—		34		—		—		34
Total liabilities	$	557	$	800	$	288	$	1	$	1,646



December 31, 2017
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	47	$	98	$	75	$	2	$	222
Interest rate swaps	—		18		—		8		26
Nuclear decommissioning trust – equity securities (c)	468		—		—		—		468
Nuclear decommissioning trust – debt securities (c)	—		430		—		—		430
Sub-total	$	515	$	546	$	75	$	10	1,146
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									290
Total assets									$	1,436
Liabilities:
Commodity contracts	$	45	$	143	$	128	$	2	$	318
Interest rate swaps	—		—		—		8		8
Total liabilities	$	45	$	143	$	128	$	10	$	326

____________


(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 consolidated balance sheets.


(c)	The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets. See Note 23.


(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 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

December 31, 2018 and 2017:



December 31, 2018
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	22	$	(48	)	$	(26	)	Valuation Model	Hourly price curve shape (c)	$0 to $110/ MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$20 to $120/ MWh
Electricity and weather options	31		(192		)	(161		)	Option Pricing Model	Gas to power correlation (e)	15% to 95%
										Power volatility (e)	5% to 435%
Financial transmission rights	85		(20		)	65			Market Approach (f)	Illiquid price differences between settlement points (g)	$(10) to $50/ MWh
Other (h)	15		(28		)	(13		)
Total	$	153	$	(288	)	$	(135	)



December 31, 2017
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	12	$	(33	)	$	(21	)	Valuation Model	Hourly price curve shape (c)	$0 to $40/ MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$20 to $70/ MWh
Electricity and weather options	—		(91		)	(91		)	Option Pricing Model	Gas to power correlation (e)	30% to 100%
										Power volatility (e)	5% to 180%
Financial transmission rights	45		(4		)	41			Market Approach (f)	Illiquid price differences between settlement points (g)	$0 to $15/ MWh
Other (h)	18		—			18
Total	$	75	$	(128	)	$	(53	)

____________

(a)

Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, NYISO, ISO-NE and MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within are referred to as congestion revenue rights in ERCOT and financial transmission rights in PJM, NYISO, ISO-NE and MISO regions. Electricity options consist of physical electricity options and spread options.


(b)	The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.


(c)	Primarily based on the historical range of forward average hourly ERCOT North Hub prices.


(d)	Primarily based on historical forward ERCOT power price and heat rate variability.


(e)	Based on historical forward correlation and volatility within ERCOT.


(f)	While we use the market approach, there is insufficient market data to consider the valuation liquid.


(g)	Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.


(h)	Other includes contracts for natural gas, coal options and emissions.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016. See the table below for discussion of transfers between Level 2 and Level 3 for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 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 Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016.



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Net asset (liability) balance at beginning of period (a)	$	(53	)	$	83		$	81		$	37
Total unrealized valuation gains (losses)	(363		)	(136		)	31			122
Purchases, issuances and settlements (b):
Purchases	146			69			15			37
Issuances	(41		)	(22		)	(7		)	(20		)
Settlements	76			(106		)	(30		)	(51		)
Transfers into Level 3 (c)	4			4			3			1
Transfers out of Level 3 (c)	133			71			(10		)	1
Net liabilities assumed in connections with the Merger	(37		)	—			—			—
Earn-out provision (d)	—			(16		)	—			—
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) (e)	—			—			—			(30		)
Net change (f)	(82		)	(136		)	2			60
Net asset (liability) balance at end of period	$	(135	)	$	(53	)	$	83		$	97
Unrealized valuation gains (losses) relating to instruments held at end of period	$	(174	)	$	(98	)	$	28		$	98

____________


(a)	The beginning balance for the Successor period from October 3, 2016 through December 31, 2016 reflects a $16 million adjustment to the fair value of certain Level 3 assets driven by power prices utilized by the Successor for unobservable delivery periods.


(b)	Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received.


(c)	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. For the years ended December 31, 2018 and 2017, transfers out of Level 3 primarily consists of electricity derivatives where forward pricing inputs have become observable.


(d)	Represents initial fair value of the earn-out provision agreed to as part of the Odessa Acquisition. See Note 3.


(e)	Includes fair value of Level 3 assets and liabilities as of the purchase date and any related rolloff between the purchase date and the period ended October 2, 2016.

(f)

Activity excludes change in fair value in the month positions settle. For the Successor period, substantially all changes in values of commodity contracts (excluding the net liabilities assumed in connection with the Merger and the initial fair value of the earn-out provision related to the Odessa Acquisition in 2017) are reported as operating revenues in our statements of consolidated income (loss). For the Predecessor period, substantially all changes in values of commodity contracts (excluding net liabilities assumed in the Lamar and Forney Acquisition in 2016) are reported as net gain from commodity hedging and trading activities in the statements of consolidated income (loss).

Commodity And Other Derivative Contractual Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 consolidated balance sheets at December 31, 2018 and 2017. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.



	December 31, 2018
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	707	$	22	$	1		$	—		$	730
Noncurrent assets	54		55		—			—			109
Current liabilities	—		—		(1,374		)	(2		)	(1,376		)
Noncurrent liabilities	—		—		(238		)	(32		)	(270		)
Net assets (liabilities)	$	761	$	77	$	(1,611	)	$	(34	)	$	(807	)



	December 31, 2017
	Derivative Assets					Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps			Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	190	$	—		$	—		$	—		$	190
Noncurrent assets	30		22			2			4			58
Current liabilities	—		(4		)	(216		)	(4		)	(224		)
Noncurrent liabilities	—		—			(102		)	—			(102		)
Net assets (liabilities)	$	220	$	18		$	(316	)	$	—		$	(78	)

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

The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects. 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.



	Successor								Predecessor
	Year Ended December 31,					Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Derivative (statements of consolidated income (loss) presentation)	2018			2017		Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Commodity contracts (Operating revenues)	$	(855	)	$	56	$	(92	)	$	—
Commodity contracts (Fuel, purchased power costs and delivery fees)	18			6		21			—
Commodity contracts (Net gain from commodity hedging and trading activities)	—			—		—			194
Interest rate swaps (Interest expense and related charges)	(11		)	2		(11		)	—
Net gain (loss)	$	(848	)	$	64	$	(82	)	$	194

Offsetting Assets and Liabilities

The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:



	December 31, 2018												December 31, 2017
	Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)			Net Amounts			Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)			Net Amounts
Derivative assets:
Commodity contracts	$	761		$	(593	)	$	(1	)	$	167		$	220		$	(113	)	$	(1	)	$	106
Interest rate swaps	77			(26		)	—			51			18			—			—			18
Total derivative assets	838			(619		)	(1		)	218			238			(113		)	(1		)	124
Derivative liabilities:
Commodity contracts	(1,611		)	593			109			(909		)	(316		)	113			1			(202		)
Interest rate swaps	(34		)	26			—			(8		)	—			—			—			—
Total derivative liabilities	(1,645		)	619			109			(917		)	(316		)	113			1			(202		)
Net amounts	$	(807	)	$	—		$	108		$	(699	)	$	(78	)	$	—		$	—		$	(78	)

____________


(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.

Schedule of Gross Notional Amounts of Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at December 31, 2018 and 2017:



	December 31, 2018		December 31, 2017
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	7,011		1,259		Million MMBtu
Electricity	317,572		114,129		GWh
Financial Transmission Rights (b)	172,611		110,913		GWh
Coal	45		2		Million U.S. tons
Fuel oil	60		5		Million gallons
Uranium	50		325		Thousand pounds
Emissions	10		—		Million tons
Interest rate swaps – floating/fixed (c)	$	7,717	$	3,000	Million U.S. 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 ISOs or RTOs.


(c)	Includes notional amounts of interest rate swaps with maturity dates through July 2026.

The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:



	December 31,
	2018			2017
Fair value of derivative contract liabilities (a)	$	(856	)	$	(204	)
Offsetting fair value under netting arrangements (b)	218			103
Cash collateral and letters of credit	190			41
Liquidity exposure	$	(448	)	$	(60	)

____________


(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.

Pension and Other Postretirement Employee Benefits (OPEB) Plans (Tables)

12 Months Ended

Dec. 31, 2018

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Pension and OPEB Costs [Table Text Block]

Pension and OPEB Costs



	Successor						Predecessor
	Year Ended December 31, 2018		Year Ended December 31, 2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Pension costs	$	14	$	6	$	2	$	4
OPEB costs	9		6		2		—
Total benefit costs recognized as expense	$	23	$	12	$	4	$	4

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

At December 31, 2018 and 2017, the Retirement Plan assets measured at fair value on a recurring basis consisted of the following:



	December 31,
	2018								2017
	Level 1		Level 2			Total			Level 2
Asset Category:
Interest-bearing cash	$	—	$	(6	)	$	(6	)	$	(7	)
Fixed income securities:
Corporate bonds (a)	57		61			118			65
U.S. Treasuries	—		25			25			29
Other (b)	—		6			6			7
Total assets categorized as Level 1 or 2	57		86			143			94
Assets measured at net asset value (c):
Commingled trusts						18			2
Equity securities:
U.S.						119			14
International						73			13
Fixed income securities:
Corporate bonds (a)						137			5
Total assets measured at net asset value						347			34
Total assets						$	490		$	128

___________


(a)	Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.


(b)	Other consists primarily of taxable municipal bonds.


(c)	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. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to total Vistra Retirement Plan assets.

Fair Value Measurement of Pension Plan Assets

At December 31, 2018 and 2017, the Retirement Plan assets measured at fair value on a recurring basis consisted of the following:



	December 31,
	2018								2017
	Level 1		Level 2			Total			Level 2
Asset Category:
Interest-bearing cash	$	—	$	(6	)	$	(6	)	$	(7	)
Fixed income securities:
Corporate bonds (a)	57		61			118			65
U.S. Treasuries	—		25			25			29
Other (b)	—		6			6			7
Total assets categorized as Level 1 or 2	57		86			143			94
Assets measured at net asset value (c):
Commingled trusts						18			2
Equity securities:
U.S.						119			14
International						73			13
Fixed income securities:
Corporate bonds (a)						137			5
Total assets measured at net asset value						347			34
Total assets						$	490		$	128

___________


(a)	Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.


(b)	Other consists primarily of taxable municipal bonds.


(c)	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. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to total Vistra Retirement Plan assets.

Schedule of Health Care Cost Trend Rates [Table Text Block]

The following tables provide information regarding the assumed health care cost trend rates.



	Successor
	December 31, 2018		December 31, 2017
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year	6.70	%	7.00	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2026		2026
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year	9.90	%	10.66	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2027		2026

Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.



	December 31,
	2018		2017
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	615	$	163
Accumulated benefit obligation	$	611	$	157
Plan assets	$	490	$	128

Schedule of Allocation of Plan Assets [Table Text Block]

Pension Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets.

The target asset allocation ranges of pension plan investments by asset category are as follows:



	Target Allocation Ranges
Asset Category:	Vistra Energy Plan				Dynegy Plan				EEI Plan
Fixed income	65	%	-	75%	45	%	-	55%	43	%	-	53%
Global equity securities	16	%	-	24%	29	%	-	37%	30	%	-	38%
Real estate	4	%	-	8%	8	%	-	12%	9	%	-	13%
Credit strategies	3	%	-	7%	6	%	-	10%	6	%	-	10%

Schedule of Assumptions Used [Table Text Block]

Expected Long-Term Rate of Return on Assets Assumption

The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.



	Retirement Plan
	Expected Long-Term Rate of Return
Asset Class:	Vistra Energy Plan		Dynegy Plan		EEI Plan
Fixed income securities	4.0	%	3.9	%	3.9	%
Global equity securities	7.5	%	7.5	%	7.5	%
Real estate	5.4	%	5.4	%	5.4	%
Credit strategies	6.8	%	6.8	%	6.8	%
Weighted average	4.8	%	5.3	%	5.6	%

Schedule of Expected Benefit Payments [Table Text Block]

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:



	2019		2020		2021		2022		2023		2024-28
Pension benefits	$	46	$	45	$	46	$	46	$	46	$	216
OPEB	$	10	$	11	$	11	$	11	$	11	$	49

Pension Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

Detailed Information Regarding Pension Benefits

The following information is based on a December 31, 2018, 2017 and 2016 measurement dates:



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate (Vistra Energy Plan)	3.74		%	4.31		%	3.79		%
Discount rate (Dynegy Plan & EEI Plan)	4.05		%	—		%	—		%
Expected return on plan assets (Vistra Energy Plan)	4.56		%	4.86		%	4.89		%
Expected return on plan assets (Dynegy Plan)	5.94		%	—		%	—		%
Expected return on plan assets (EEI Plan)	4.74		%	—		%	—		%
Expected rate of compensation increase (Vistra Energy Plan)	3.62		%	3.50		%	3.50		%
Expected rate of compensation increase (Dynegy Plan & EEI Plan)	3.50		%	—		%	—		%
Interest crediting rate for cash balance plans (Vistra Energy Plan)	3.50		%	4.00		%	4.00		%
Interest crediting rate for cash balance plans (Dynegy Plan & EEI Plan)	4.25		%	—		%	—		%
Components of Net Pension Cost:
Service cost	$	15		$	5		$	2
Interest cost	21			6			1
Expected return on assets	(23		)	(5		)	(1		)
Immediate pension cost	$	1		$	—		$	—
Net periodic pension cost	$	14		$	6		$	2
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss	$	14		$	3		$	(4	)
Total recognized in net periodic benefit cost and other comprehensive income	$	28		$	9		$	(2	)
Assumptions Used to Determine Benefit Obligations:
Discount rate (Vistra Plan)	4.37		%	3.74		%	4.31		%
Expected rate of compensation increase (Vistra Plan)	3.35		%	3.62		%	3.50		%
Discount rate (Dynegy Plan)	4.37		%	—		%	—		%
Expected rate of compensation increase (Dynegy Plan)	3.35		%	—		%	—		%
Interest crediting rate for cash balance plans (Vistra Energy Plan)	3.50		%	3.50		%	4.00		%
Interest crediting rate for cash balance plans (Dynegy Plan & EEI)	3.50		%	—		%	—		%

For the year ended December 31, 2018, the net actuarial loss of $14 million was driven by losses attributable to actual asset performance falling short of expectations and plan experience different than expected, partially offset by gains attributable to increasing discount rates due to changes in the corporate bond markets, economic assumption updates to reflect current market conditions and life expectancy projection updates.

For the year ended December 31, 2017, the net actuarial loss of $3 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and demographic assumption updates to reflect current expectations, partially offset by gains attributable to actual asset performance exceeding expectations, economic assumption updates to reflect current market conditions, life expectancy projection updates and plan experience different than expected.

For the period from October 3, 2016 through December 31, 2016, the net actuarial gain of $4 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by losses attributable to actual asset performance falling short of expectations.



	Successor
	Year Ended December 31,
	2018			2017
Change in Pension Obligation:
Projected benefit obligation at beginning of period	$	163		$	144
Acquisitions	502			—
Service cost	15			5
Interest cost	21			6
Settlement	(28		)	—
Actuarial (gain) loss	(34		)	13
Benefits paid	(24		)	(5		)
Projected benefit obligation at end of year	$	615		$	163
Accumulated benefit obligation at end of year	$	611		$	157
Change in Plan Assets:
Fair value of assets at beginning of period	$	128		$	117
Acquisitions	428			—
Employer contributions	12			—
Settlement	(28		)	—
Actual gain (loss) on assets	(26		)	16
Benefits paid	(24		)	(5		)
Fair value of assets at end of year	$	490		$	128
Funded Status:
Projected pension benefit obligation	$	(615	)	$	(163	)
Fair value of assets	490			128
Funded status at end of year	$	(125	)	$	(35	)
Amounts Recognized in the Balance Sheet Consist of:
Other current liabilities	$	—		$	—
Other noncurrent liabilities	(125		)	(35		)
Net liability recognized	$	(125	)	$	(35	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net gain (loss)	$	(13	)	$	1

Other Postretirement Benefits Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

Detailed Information Regarding Postretirement Benefits Other Than Pensions

The following OPEB information is based on a December 31, 2018 measurement date:



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate (Vistra Energy Plan)	3.67		%	4.11		%	4.00		%
Discount rate (Oncor Plan)	—		%	4.18		%	3.69		%
Discount rate (Dynegy Plan)	4.04		%	—		%	—		%
Expected return on plan assets (EEI Union)	5.10		%	—		%	—		%
Expected return on plan assets (EEI Salaried)	4.47		%	—		%	—		%
Components of Net Postretirement Benefit Cost:
Service cost	$	2		$	2		$	1
Interest cost	5			4			1
Expected return on plan assets	(1		)	—			—
Amortization of unrecognized amounts	3			—			—
Plan amendments (a)	—			—			(4		)
Net periodic OPEB cost (income)	$	9		$	6		$	(2	)
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss and prior service (credit) cost	$	(6	)	$	26		$	(5	)
Total recognized in net periodic benefit cost and other comprehensive income	$	3		$	32		$	(7	)
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate (Vistra Energy Plan)	4.35		%	3.67		%	4.11		%
Discount rate (Split-Participant Plan)	4.35		%	3.67		%	—		%
Discount rate (Oncor Plan)	—		%	—		%	4.18		%
Discount rate (Dynegy Plan)	4.35		%	—		%	—		%
Expected return on plan assets (EEI Union)	5.36		%	—		%	—		%
Expected return on plan assets (EEI Salaried)	4.70		%	—		%	—		%

___________


(a)	Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees.

For the year ended December 31, 2018, the net actuarial gain of $7 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, life expectancy projection updates and updates to health care related assumptions, partially offset by losses attributable to actual asset performance falling short of expectations and plan experience different than expected.

For the year ended December 31, 2017, the net actuarial loss of $15 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets, demographic assumption updates to reflect current expectations and updates to health care related assumptions, partially offset by gains attributable to life expectancy projection updates and plan experience different than expected.

For the period from October 3, 2016 through December 31, 2016, the net actuarial gain of $5 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets and plan experience different than expected.



	Year Ended December 31,
	2018			2017
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	115		$	88
Acquisition	37			—
Service cost	2			2
Interest cost	5			4
Participant contributions	2			2
Plan amendments (a)	4			11
Actuarial (gain) loss	(9		)	15
Benefits paid	(12		)	(7		)
Benefit obligation at end of year	$	144		$	115
Change in Plan Assets:
Fair value of assets at beginning of year	$	—		$	—
Acquisition	32			—
Employer contributions	8			5
Participant contributions	2			2
Benefits paid	(12		)	(7		)
Actual loss on assets	(1		)	—
Fair value of assets at end of year	$	29		$	—
Funded Status:
Benefit obligation	$	(144	)	$	(115	)
Fair value of assets	29			—
Funded status at end of year	$	(115	)	$	(115	)
Amounts Recognized on the Balance Sheet Consist of:
Other noncurrent assets	$	14		$	—
Other current liabilities	$	(8	)	$	(6	)
Other noncurrent liabilities	(121		)	(109		)
Net liability recognized	$	(115	)	$	(115	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss and prior service cost	$	15		$	20

___________


(a)	For the year ended December 31, 2018, plan amendments relate to changes in Dynegy plans and retiree medical cost structure. For the year ended December 31, 2017, plan amendments relate to the contractual arrangement with Oncor covering Split Participants.

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Stock-Based Compensation Awards Assumed in Merger

Assumption of Dynegy Stock Compensation Plans

At the Merger Date, Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra Energy's common stock, after giving effect to the Exchange Ratio.



Instrument Type	Dynegy Awards Prior to the Merger Date	Vistra Awards Converted at the Merger Date	Fair Value of Awards (a)
Stock Options	4,096,027	2,670,610	$	10
Restricted Stock Units	5,718,148	3,056,689	61
Performance Units	1,538,133	938,721	18
Total			$	89

____________


(a)	$26 million was attributable to pre-combination service and considered part of the purchase price (see Note 2). $33 million was recognized immediately as compensation expense due to accelerated vesting as a result of the Merger. $30 million will be amortized as compensation expense over the remaining service period and is recorded in additional paid in capital in the consolidated balance sheet.

Schedule of Stock-based Compensation Expense Recorded

Stock-based compensation expense is reported as SG&A in the statement of consolidated net income (loss) as follows:



	Successor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016
Total stock-based compensation expense	$	73		$	19		$	3
Income tax benefit	(15		)	(7		)	(1		)
Stock based-compensation expense, net of tax	$	58		$	12		$	2

Schedule of Stock-based Compensation Stock Options Activity

Stock options outstanding at December 31, 2018 are all held by current employees. The following table summarizes our stock option activity:



	Successor
	Year Ended December 31, 2018
	Stock Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value (in millions)
Total outstanding at beginning of period	8,136		$	14.44	9.0	$	32.4
Awards converted at Merger Date	2,671		$	23.19
Granted	5,268		$	19.67
Exercised	(1,082	)	$	13.91
Forfeited or expired	(494	)	$	15.14
Total outstanding at end of period	14,499		$	17.97	7.3	$	85.1
Exercisable at December 31, 2018	4,696		$	18.88	5.2	$	32.6

Schedule of Share-based Compensation, Restricted Stock Units Award Activity

The following table summarizes our restricted stock unit activity:



	Successor
	Year Ended December 31, 2018
	Restricted Stock Units (in thousands)		Weighted Average Grant Date Fair Value		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value (in millions)
Total outstanding at beginning of period	2,375		$	16.91	1.9	$	43.5
Awards converted at Merger Date	3,057		$	15.52
Granted	133		$	22.41
Exercised	(2,114	)	$	15.48
Forfeited or expired	(225	)	$	16.69
Total outstanding at end of period	3,226		$	16.77	1.1	$	73.8
Expected to vest	3,222		$	16.85	1.0	$	73.7

Segment Information (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Schedule of segment reporting information, by segment

.



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Operating revenues (a)
Retail	$	5,597		$	4,058		$	912
ERCOT	2,634			1,794			212
PJM	1,725			—			—
NY/NE	817			—			—
MISO	720			—			—
Asset Closure	50			964			238
Corporate and Other (b)	208			—			—
Eliminations	(2,607		)	(1,386		)	(171		)
Consolidated operating revenues	$	9,144		$	5,430		$	1,191
Depreciation and amortization
Retail	$	(318	)	$	(430	)	$	(153	)
ERCOT	(416		)	(229		)	(53		)
PJM	(413		)	—			—
NY/NE	(152		)	—			—
MISO	(9		)	—			—
Asset Closure	—			(1		)	—
Corporate and Other (b)	(86		)	(40		)	(11		)
Eliminations				1			$	1
Consolidated depreciation and amortization	$	(1,394	)	$	(699	)	$	(216	)
Operating income (loss)
Retail	$	690		$	461		$	111
ERCOT	(70		)	(118		)	(271		)
PJM	100			—			—
NY/NE	70			—			—
MISO	36			—			—
Asset Closure	(50		)	(68		)	16
Corporate and Other (b)	(281		)	(78		)	(17		)
Eliminations	(4		)	1			—
Consolidated operating income (loss)	$	491		$	198		$	(161	)
Interest expense and related charges
Retail	$	(7	)	$	—		$	—
ERCOT	(12		)	(21		)	1
PJM	(8		)	—			—
NY/NE	(2		)	—			—
MISO	(1		)	—			—
Corporate and Other (b)	(613		)	(252		)	(66		)
Eliminations	71			80			5
Consolidated interest expense and related charges	$	(572	)	$	(193	)	$	(60	)



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Income tax (expense) benefit (all Corporate and Other)	$	45		$	(504	)	$	70
Net income (loss)
Retail	$	712		$	495		$	114
ERCOT	(55		)	(114		)	(268		)
PJM	100			—			—
NY/NE	79			—			—
MISO	35			—			—
Asset Closure	(49		)	(63		)	17
Corporate and Other (b)	(876		)	(573		)	(26		)
Eliminations	(2		)	1			—
Consolidated net income (loss)	$	(56	)	$	(254	)	$	(163	)
Capital expenditures, excluding LTSA
Retail	$	1		$	—		$	5
ERCOT	283			150			84
PJM	41			—			—
NY/NE	10			—			—
MISO	3			—			—
Corporate and Other (b)	58			26			—
Consolidated capital expenditures	$	396		$	176		$	89

____________


(a)	The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:



	Successor
	Year Ended December 31, 2018			Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Retail	$	(12	)	$	18		$	(6	)
ERCOT	(483		)	(305		)	(295		)
PJM	(50		)	—			—
NY/NE	(40		)	—			—
MISO	3			—			—
Corporate and Other (b)	(15		)	—			—
Eliminations (1)	217			154			113
Consolidated unrealized net losses from mark-to-market valuations of commodity positions included in operating revenues	$	(380	)	$	(133	)	$	(188	)

____________


(1)	Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.


(b)	Other includes CAISO operations. Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate net income.



	December 31,
	2018			2017
Total assets
Retail	$	7,699		$	6,156
ERCOT	9,347			6,821
PJM	7,188			—
NY/NE	2,722			—
MISO	836			—
Asset Closure	254			248
Corporate and Other and Eliminations	(2,022		)	1,375
Consolidated total assets	$	26,024		$	14,600

Prior to the Effective Date, our Predecessor's chief operating decision maker reviewed the retail electricity, wholesale generation and commodity risk management activities together. Consequently, there were no reportable business segments for TCEH.

Supplementary Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Supplementary Financial Information [Abstract]

Schedule of other income and deductions

Other Income and Deductions



	Successor						Predecessor
	Year Ended December 31,				Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
	2018		2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Other income:
Office space sublease rental income (a)	$	8	$	11	$	2	$	—
Mineral rights royalty income (b)	—		3		1		3
Sale of land (b)	3		4		—		—
Curtailment gain on employee benefit plans (a)	—		—		4		—
Insurance settlement	16		—		—		9
Interest income	18		15		1		3
All other	2		4		2		4
Total other income	$	47	$	37	$	10	$	19
Other deductions:
Write-off of generation equipment (b)	—		2		—		45
Adjustment to asbestos liability	—		—		—		11
All other	5		3		—		19
Total other deductions	$	5	$	5	$	—	$	75

____________


(a)	Reported in Corporate and Other non-segment (Successor period only).


(b)	Reported in ERCOT segment (Successor period only).

Schedule of restricted cash

Restricted Cash



	December 31, 2018				December 31, 2017
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the Vistra Operations Credit Facilities (Note 14)	$	—	$	—	$	—	$	500
Amounts related to restructuring escrow accounts	57		—		59		—
Total restricted cash	$	57	$	—	$	59	$	500

Schedule of accounts, notes, loans and financing receivable

Allowance for Uncollectible Accounts Receivable



	Successor								Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016
Allowance for uncollectible accounts receivable at beginning of period	$	14		$	10		$	—	$	9
Increase for bad debt expense	56			43			10		20
Decrease for account write-offs	(51		)	(39		)	—		(16		)
Allowance for uncollectible accounts receivable at end of period	$	19		$	14		$	10	$	13

Trade Accounts Receivable



	December 31,
	2018			2017
Wholesale and retail trade accounts receivable	$	1,106		$	596
Allowance for uncollectible accounts	(19		)	(14		)
Trade accounts receivable — net	$	1,087		$	582

Schedule of inventories by major category

Inventories by Major Category



	December 31,
	2018		2017
Materials and supplies	$	286	$	149
Fuel stock	115		83
Natural gas in storage	11		21
Total inventories	$	412	$	253

Summary of other investments

Other Investments



	December 31,
	2018		2017
Nuclear plant decommissioning trust	$	1,170	$	1,188
Assets related to employee benefit plans (Note 19)	31		—
Land	49		49
Miscellaneous other	—		3
Total other investments	$	1,250	$	1,240

Summary of investments in the fund

A summary of investments in the fund follows:



	December 31, 2018
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	444	$	7	$	(8	)	$	443
Equity securities (c)	280		448		(1		)	727
Total	$	724	$	455	$	(9	)	$	1,170



	December 31, 2017
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	418	$	14	$	(2	)	$	430
Equity securities (c)	265		495		(2		)	758
Total	$	683	$	509	$	(4	)	$	1,188

____________


(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 government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of 3.69% and 3.55% at December 31, 2018 and 2017, respectively, and an average maturity of 8 years and 9 years at December 31, 2018 and 2017, respectively.


(c)	The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI Inc. EAFE Index for non-U.S. equity investments.

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
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Realized gains	$	2		$	9		$	1		$	3
Realized losses	$	(9	)	$	(11	)	$	—		$	(2	)
Proceeds from sales of securities	$	252		$	252		$	25		$	201
Investments in securities	$	(274	)	$	(272	)	$	(30	)	$	(215	)

Schedule of property, plant and equipment

Property, Plant and Equipment



	December 31,
	2018			2017
Power generation and structures	$	14,604		$	3,966
Land	642			540
Office and other equipment	182			120
Total	15,428			4,626
Less accumulated depreciation	(1,284		)	(282		)
Net of accumulated depreciation	14,144			4,344
Nuclear fuel (net of accumulated amortization of $189 million and $111 million)	191			158
Construction work in progress	277			318
Property, plant and equipment — net	$	14,612		$	4,820

Depreciation expense totaled $1.024 billion, $236 million, $54 million and $401 million for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.

Our property, plant and equipment consist of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements. At December 31, 2018, buildings and improvements includes a capital lease for an office building that totaled $62 million with accumulated depreciation of $11 million. The estimated remaining useful lives range from 1 to 35 years for our property, plant and equipment.

Schedule of asset retirement and mining reclamation obligations

The following table summarizes the changes to these obligations, reported as asset retirement obligations (current and noncurrent liabilities) in our consolidated balance sheets, for the Successor period for the years ended December 31, 2018 and 2017:



	Nuclear Plant Decommissioning		Mining Land Reclamation			Coal Ash and Other			Total
Successor:
Liability at December 31, 2016	1,200		375			151			1,726
Additions:
Accretion	33		18			8			59
Adjustment for change in estimates (a)	—		81			44			125
Incremental reclamation costs (b)	—		—			62			62
Reductions:
Payments	—		(36		)	—			(36		)
Liability at December 31, 2017	1,233		438			265			1,936
Additions:
Accretion	43		22			28			93
Adjustment for change in estimates	—		56			(89		)	(33		)
Obligations assumed in the Merger	—		2			475			477
Reductions:
Payments	—		(76		)	(24		)	(100		)
Liability at December 31, 2018	1,276		442			655			2,373
Less amounts due currently	—		(106		)	(50		)	(156		)
Noncurrent liability at December 31, 2018	$	1,276	$	336		$	605		$	2,217

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:



	December 31,
	2018		2017
Retirement and other employee benefits	$	270	$	166
Uncertain tax positions, including accrued interest	4		—
Other	66		54
Total other noncurrent liabilities and deferred credits	$	340	$	220

Schedule of fair value of debt

Fair Value of Debt



		December 31, 2018				December 31, 2017
Long-Term Debt (see Note 14):	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	5,820	$	5,599	$	4,323	$	4,334
Vistra Operations Senior Notes	Level 2	987		963		—		—
Vistra Energy Senior Notes	Level 2	3,819		3,765		—		—
7.000% Amortizing Notes	Level 2	23		24		—		—
Forward Capacity Agreements	Level 3	221		221		—		—
Equipment Financing Agreements	Level 3	102		102		—		—
Mandatorily redeemable subsidiary preferred stock	Level 2	70		70		70		70
Building Financing	Level 2	23		21		30		27

Schedule of supplemental cash flow information

Supplemental Cash Flow Information

The following table reconciles cash, cash equivalents and restricted cash reported in our statements of consolidated cash flows to the amounts reported in our balance sheets at December 31, 2018 and 2017:



	December 31,
	2018		2017
Cash and cash equivalents	$	636	$	1,487
Restricted cash included in current assets	57		59
Restricted cash included in noncurrent assets	—		500
Total cash, cash equivalents and restricted cash	$	693	$	2,046

The following table summarizes our supplemental cash flow information for the Successor period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively.



	Successor									Predecessor
	Year Ended December 31,						Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
	2018			2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016
Cash payments related to:
Interest paid (a)	$	651		$	245		$	19		$	1,064
Capitalized interest	(12		)	(7		)	(3		)	(9		)
Interest paid (net of capitalized interest) (a)	$	639		$	238		$	16		$	1,055
Income taxes	$	67		$	63		$	(2	)	$	22
Reorganization items (b)	$	—		$	—		$	—		$	104
Noncash investing and financing activities:
Construction expenditures (c)	$	79		$	12		$	1		$	53
Vistra Energy common stock issued in the Merger (Notes 2 and 16)	$	2,245		$	—		$	—		$	—

____________


(a)	Predecessor period includes amounts paid for adequate protection.


(b)	Represents cash payments made by our Predecessor for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court.


(c)	Represents end-of-period accruals for ongoing construction projects.

Schedule of quarterly financial information

Quarterly Information (Unaudited)

Unaudited results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily indicative of a full year's operations because of seasonal and other factors. Quarterly amounts may not add to full year amounts due to rounding.



	Successor
	Quarter Ended
	March 31			June 30			September 30		December 31 (b)
2018(a):
Operating revenues	$	765		$	2,574		$	3,243	$	2,562
Operating income (loss)	$	(394	)	$	231		$	650	$	4
Net income (loss)	$	(306	)	$	105		$	331	$	(186	)
Net income (loss) attributable to Vistra Energy	$	(306	)	$	108		$	330	$	(186	)
Net income (loss) per weighted average share of common stock outstanding — basic	$	(0.71	)	$	0.21		$	0.62	$	(0.35	)
Net income (loss) per weighted average share of common stock outstanding — diluted	$	(0.71	)	$	0.20		$	0.61	$	(0.35	)
2017:
Operating revenues	$	1,357		$	1,296		$	1,833	$	944
Operating income (loss)	$	155		$	53		$	452	$	(462	)
Net income (loss)	$	78		$	(26	)	$	273	$	(579	)
Net income (loss) attributable to Vistra Energy	$	78		$	(26	)	$	273	$	(579	)
Net income (loss) per weighted average share of common stock outstanding — basic	$	0.18		$	(0.06	)	$	0.64	$	(1.35	)
Net income (loss) per weighted average share of common stock outstanding — diluted	$	0.18		$	(0.06	)	$	0.64	$	(1.35	)

____________


(a)	For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.

(b)

For the Successor quarter ended December 31, 2017, operating loss includes noncash charges of $183 million related to the generation facilities retirement announcements. Net loss reflects the retirements mentioned above as well as a $451 million reduction of deferred tax assets related to the decrease in the corporate tax rate due to the TCJA (see Note 9), partially offset by $117 million of impacts of the TRA.

Supplemental Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Supplemental Condensed Consolidating Financial Information [Abstract]

Condensed Statement of Consolidated Income (Loss)

Condensed Statements of Consolidating Income (Loss)

for the Year Ended December 31, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating revenues	$	—		$	5,430		$	—	$	—	$	5,430
Fuel, purchased power costs and delivery fees	—			(2,935		)	—		—		(2,935		)
Operating costs	—			(973		)	—		—		(973		)
Depreciation and amortization	—			(699		)	—		—		(699		)
Selling, general and administrative expenses	(47		)	(553		)	—		—		(600		)
Impairment of long-lived assets	—			(25		)	—		—		(25		)
Operating income (loss)	(47		)	245			—		—		198
Other income	—			37			—		—		37
Other deductions	—			(5		)	—		—		(5		)
Interest Income	4			(4		)	—		—		—
Interest expense and related charges	—			(193		)	—		—		(193		)
Impacts of Tax Receivable Agreement	213			—			—		—		213
Income before income taxes	170			80			—		—		250
Income tax benefit (expense)	80			(584		)	—		—		(504		)
Equity in earnings (losses) of subsidiaries, net of tax	(504		)	—			—		504		—
Net income (loss)	$	(254	)	$	(504	)	$	—	$	504	$	(254	)

Condensed Statements of Consolidating Income (Loss)

for the Year Ended December 31, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	9,043		$	174		$	(73	)	$	9,144
Fuel, purchased power costs and delivery fees	—			(4,968		)	(92		)	24			(5,036		)
Operating costs	—			(1,255		)	(42		)	—			(1,297		)
Depreciation and amortization	—			(1,337		)	(57		)	—			(1,394		)
Selling, general and administrative expenses	(266		)	(660		)	(49		)	49			(926		)
Operating income (loss)	(266		)	823			(66		)	—			491
Other income	9			41			—			(3		)	47
Other deductions	—			(6		)	1			—			(5		)
Interest expense and related charges	(257		)	(309		)	(9		)	3			(572		)
Impacts of Tax Receivable Agreement	(79		)	—			—			—			(79		)
Equity in earnings of unconsolidated investment	—			17			—			—			17
Income (loss) before income taxes	(593		)	566			(74		)	—			(101		)
Income tax expense	282			(284		)	47			—			45
Equity in earnings (loss) of subsidiaries, net of tax	257			(25		)	—			(232		)	—
Net income (loss)	(54		)	257			(27		)	(232		)	(56		)
Net loss attributable to noncontrolling interest	—			—			2			—			2
Net income (loss) attributable to Vistra Energy	$	(54	)	$	257		$	(25	)	$	(232	)	$	(54	)

Condensed Statements of Consolidating Income (Loss)

for the Period from October 3, 2016 through December 31, 2016

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues	$	—		$	1,191		$	—	$	—		$	1,191
Fuel, purchased power costs and delivery fees	—			(720		)	—		—			(720		)
Operating costs	—			(208		)	—		—			(208		)
Depreciation and amortization	—			(216		)	—		—			(216		)
Selling, general and administrative expenses	(7		)	(201		)	—		—			(208		)
Operating income (loss)	(7		)	(154		)	—		—			(161		)
Other income	—			10			—		—			10
Interest expense and related charges	—			(60		)	—		—			(60		)
Impacts of Tax Receivable Agreement	(22		)	—			—		—			(22		)
Income (loss) before income taxes	(29		)	(204		)	—		—			(233		)
Income tax expense	(204		)	274			—		—			70
Equity in earnings (loss) of subsidiaries, net of tax	70			—			—		(70		)	—
Net income (loss)	(163		)	70			—		(70		)	(163		)

Condensed Statement of Consolidating Other Comprehensive Income

Condensed Statements of Consolidating Comprehensive Income (Loss)

for the Year Ended December 31, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net income (loss)	$	(254	)	$	(504	)	$	—	$	504	$	(254	)
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	(23		)	(29		)	—		29		(23		)
Total other comprehensive income	(23		)	(29		)	—		29		(23		)
Comprehensive income (loss)	$	(277	)	$	(533	)	$	—	$	533	$	(277	)

Condensed Statements of Consolidating Comprehensive Income (Loss)

for the Period from October 3, 2016 through December 31, 2016

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	(163	)	$	70	$	—	$	(70	)	$	(163	)
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	6			6		—		(6		)	6
Total other comprehensive income	6			6		—		(6		)	6
Comprehensive income (loss)	(157		)	76		—		(76		)	(157		)

Condensed Statements of Consolidating Comprehensive Income (Loss)

for the Year Ended December 31, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	(54	)	$	257		$	(27	)	$	(232	)	$	(56	)
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	—			(6		)	—			—			(6		)
Adoption of accounting standard	1			—			—			—			1
Total other comprehensive income	1			(6		)	—			—			(5		)
Comprehensive income (loss)	(53		)	251			(27		)	(232		)	(61		)
Comprehensive loss attributable to noncontrolling interest	—			—			2			—			2
Comprehensive income (loss) attributable to Vistra Energy	$	(53	)	$	251		$	(25	)	$	(232	)	$	(59	)

Condensed Statements of Consolidating Cash Flow

Condensed Statements of Consolidating Cash Flows

for the Year Ended December 31, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(108	)	$	1,494		$	—	$	—		$	1,386
Cash flows — financing activities:
Repayments/repurchases of debt	—			(191		)	—		—			(191		)
Cash dividend paid	—			(1,505		)	—		1,505			—
Debt financing fees	—			(8		)	—		—			(8		)
Other, net	—			(2		)	—		—			(2		)
Cash provided by (used in) financing activities	—			(1,706		)	—		1,505			(201		)
Cash flows — investing activities:
Capital expenditures	—			(114		)	—		—			(114		)
Nuclear fuel purchases	—			(62		)	—		—			(62		)
Development and growth expenditures	—			(190		)	—		—			(190		)
Odessa acquisition	(330		)	(25		)	—		—			(355		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			252			—		—			252
Investments in nuclear decommissioning trust fund securities	—			(272		)	—		—			(272		)
Dividend received from subsidiaries	1,505								(1,505		)	—
Other, net	—			14			—		—			14
Cash provided by (used in) investing activities	1,175			(397		)	—		(1,505		)	(727		)
Net change in cash, cash equivalents and restricted cash	1,067			(609		)	—		—			458
Cash, cash equivalents and restricted cash — beginning balance	116			1,472			—		—			1,588
Cash, cash equivalents and restricted cash — ending balance	$	1,183		$	863		$	—	$	—		$	2,046

Condensed Statements of Consolidating Cash Flows

for the Year Ended December 31, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(125	)	$	1,917		$	(321	)	$	—		$	1,471
Cash flows — financing activities:
Issuances of long-term debt	—			1,000			—			—			1,000
Repayments/repurchases of debt	(4,543		)	1,468			—			—			(3,075		)
Borrowings under accounts receivable securitization program	—			—			339						339
Cash dividend paid	—			(4,668		)	—			4,668			—
Stock repurchase	(763		)	—			—			—			(763		)
Debt tender offer and other financing fees	(179		)	(57		)	—			—			(236		)
Other, net	12			—			—			—			12
Cash provided by (used in) financing activities	(5,473		)	(2,257		)	339			4,668			(2,723		)
Cash flows — investing activities:
Capital expenditures	(24		)	(351		)	(3		)	—			(378		)
Nuclear fuel purchases	—			(118		)	—			—			(118		)
Cash acquired in the Merger	—			445			—			—			445
Development and growth expenditures	—			(31		)	(3		)	—			(34		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			252			—			—			252
Investments in nuclear decommissioning trust fund securities	—			(274		)	—			—			(274		)
Dividend received from subsidiaries	4,668									(4,668		)	—
Other, net	(1		)	7			—			—			6
Cash provided by (used in) investing activities	4,643			(70		)	(6		)	(4,668		)	(101		)
Net change in cash, cash equivalents and restricted cash	(955		)	(410		)	12			—			(1,353		)
Cash, cash equivalents and restricted cash — beginning balance	1,183			863			—			—			2,046
Cash, cash equivalents and restricted cash — ending balance	$	228		$	453		$	12		$	—		$	693

Condensed Statements of Consolidating Cash Flows

for the Period from October 3, 2016 through December 31, 2016

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(36	)	$	117		$	—	$	—		$	81
Cash flows — financing activities:
Issuances of long-term debt	—			1,000			—		—			1,000
Cash dividend paid	—			(997		)	—		997			—
Special dividends	(992		)	—			—		—			(992		)
Other, net	1			(3		)	—		—			(2		)
Cash provided by (used in) financing activities	(991		)	—			—		997			6
Cash flows — investing activities:
Capital expenditures	—			(48		)	—		—			(48		)
Nuclear fuel purchases	—			(41		)	—		—			(41		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			25			—		—			25
Investments in nuclear decommissioning trust fund securities	—			(30		)	—		—			(30		)
Dividend received from subsidiaries	997			—			—		(997		)	—
Other, net	—			1			—		—			1
Cash provided by (used in) investing activities	997			(93		)	—		(997		)	(93		)
Net change in cash, cash equivalents and restricted cash	(30		)	24			—		—			(6		)
Cash, cash equivalents and restricted cash — beginning balance	146			1,448			—		—			1,594
Cash, cash equivalents and restricted cash — ending balance	$	116		$	1,472		$	—	$	—		$	1,588

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet as of December 31, 2017

(Millions of Dollars)



	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,124	$	363	$	—	$	—		$	1,487
Restricted cash	59		—		—		—			59
Trade accounts receivable — net	4		578		—		—			582
Inventories	—		253		—		—			253
Commodity and other derivative contractual assets	—		190		—		—			190
Margin deposits related to commodity contracts	—		30		—		—			30
Prepaid expense and other current assets	—		72		—		—			72
Total current assets	1,187		1,486		—		—			2,673
Restricted cash	—		500		—		—			500
Investments	—		1,240		—		—			1,240
Investment in affiliated companies	5,632		—		—		(5,632		)	—
Property, plant and equipment — net	—		4,820		—		—			4,820
Goodwill	—		1,907		—		—			1,907
Identifiable intangible assets — net	—		2,530		—		—			2,530
Commodity and other derivative contractual assets	—		58		—		—			58
Accumulated deferred income taxes	5		705		—		—			710
Other noncurrent assets	6		156		—		—			162
Total assets	$	6,830	$	13,402	$	—	$	(5,632	)	$	14,600
LIABILITIES AND EQUITY
Current liabilities:
Long-term debt due currently	—		44		—		—			44
Trade accounts payable	11		462		—		—			473
Commodity and other derivative contractual liabilities	—		224		—		—			224
Margin deposits related to commodity contracts	—		4		—		—			4
Accrued taxes	58		—		—		—			58
Accrued taxes other than income	—		136		—		—			136
Accrued interest	—		16		—		—			16
Asset retirement obligations	—		99		—		—			99
Other current liabilities	86		211		—		—			297
Total current liabilities	155		1,196		—		—			1,351
Long-term debt, less amounts due currently	—		4,379		—		—			4,379
Commodity and other derivative contractual liabilities	—		102		—		—			102
Tax Receivable Agreement obligation	333		—		—		—			333
Asset retirement obligations	—		1,837		—		—			1,837
Identifiable intangible liabilities — net	—		36		—		—			36
Other noncurrent liabilities and deferred credits	—		220		—		—			220
Total liabilities	488		7,770		—		—			8,258
Total equity	6,342		5,632		—		(5,632		)	6,342
Total liabilities and equity	$	6,830	$	13,402	$	—	$	(5,632	)	$	14,600

Condensed Consolidating Balance Sheet as of December 31, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	171	$	453	$	12	$	—		$	636
Restricted cash	57		—		—		—			57
Advances to affiliates	11		11		—		(22		)	—
Trade accounts receivable — net	4		729		464		(110		)	1,087
Accounts receivable — affiliates	—		245		—		(245		)	—
Notes due from affiliates	—		101		—		(101		)	—
Income taxes receivable	—		1		—		(1		)	—
Inventories	—		391		21		—			412
Commodity and other derivative contractual assets	—		730		—		—			730
Margin deposits related to commodity contracts	—		361		—		—			361
Prepaid expense and other current assets	2		134		16		—			152
Total current assets	245		3,156		513		(479		)	3,435
Investments	—		1,218		32		—			1,250
Investment in unconsolidated subsidiary	—		131		—		—			131
Investment in affiliated companies	11,186		263		—		(11,449		)	—
Property, plant and equipment — net	15		14,017		580		—			14,612
Goodwill	—		2,068		—		—			2,068
Identifiable intangible assets — net	10		2,480		3		—			2,493
Commodity and other derivative contractual assets	—		109		—		—			109
Accumulated deferred income taxes	809		599		—		(72		)	1,336
Other noncurrent assets	255		330		5		—			590
Total assets	$	12,520	$	24,371	$	1,133	$	(12,000	)	$	26,024
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program	$	—	$	—	$	339	$	—		$	339
Advances from affiliates	—		—		22		(22		)	—
Long-term debt due currently	23		163		5		—			191
Trade accounts payable	2		928		121		(106		)	945
Accounts payable — affiliates	236		—		9		(245		)	—
Notes due to affiliates	—		—		101		(101		)	—
Commodity and other derivative contractual liabilities	—		1,376		—		—			1,376
Margin deposits related to commodity contracts	—		4		—		—			4
Accrued taxes	11		—		—		(1		)	10
Accrued taxes other than income	—		181		1		—			182
Accrued interest	48		29		4		(4		)	77
Asset retirement obligations	—		156		—		—			156
Other current liabilities	74		267		4		—			345
Total current liabilities	394		3,104		606		(479		)	3,625

Condensed Consolidating Balance Sheet as of December 31, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Long-term debt, less amounts due currently	3,819		7,027		28		—			10,874
Commodity and other derivative contractual liabilities	—		270		—		—			270
Accumulated deferred income taxes	—		—		82		(72		)	10
Tax Receivable Agreement obligation	420		—		—		—			420
Asset retirement obligations	—		2,203		14		—			2,217
Identifiable intangible liabilities — net	—		278		123		—			401
Other noncurrent liabilities and deferred credits	20		303		17		—			340
Total liabilities	4,653		13,185		870		(551		)	18,157
Total stockholders' equity	7,867		11,186		259		(11,449		)	7,863
Noncontrolling interest in subsidiary	—		—		4		—			4
Total liabilities and equity	$	12,520	$	24,371	$	1,133	$	(12,000	)	$	26,024

Business And Significant Accounting Policies (Narrative) (Details) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016 USD ($)	Oct. 02, 2016 USD ($)	Dec. 31, 2018 USD ($) Reportable_segment	Dec. 31, 2017 USD ($)
Number of reportable segments (in reportable segments) \| Reportable_segment			6
Noncontrolling interest, ownership percentage by noncontrolling owners			20.00%
Operating Loss And Alternative Minimum Tax Carryforwards Acquired In Merger			$ 4,200
Luminant Generation Company LLC [Member] \| Upton County 2 Solar Facility [Member]
Reduction Of Tax Basis of Asset, Use Of Investment Tax Credit Deferral Method			78
Successor
Advertising expense	$ 9		$ 46	$ 44
Predecessor
Advertising expense		$ 35

Business And Significant Accounting Policies (Adoption of New Accounting Standards) (Details) - USD ($) $ in Millions	3 Months Ended										12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adoption of new accounting standard (Note 1)											$ 1
Impact on consolidated balance sheet:
Prepaid expense and other current assets	$ 152				$ 72						152	$ 72	$ 77
Accumulated deferred income taxes	1,336				710						1,336	710	706
Other noncurrent assets	590				162						590	162	178
Retained deficit	(1,449)				(1,410)						(1,449)	(1,410)	(1,393)
Impact on statement of consolidated income (loss)
Operating revenues									$ 1,191		9,144	5,430
Net income (loss)									(163)		(56)	(254)
Selling, general and administrative expense									(208)		(926)	(600)
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Impact on consolidated balance sheet:
Prepaid expense and other current assets	145				72						145	72
Accumulated deferred income taxes	1,349				710						1,349	710
Other noncurrent assets	559				162						559	162
Retained deficit	(1,478)				(1,410)						(1,478)	(1,410)
Impact on statement of consolidated income (loss)
Operating revenues											9,141
Net income (loss)											(68)
Selling, general and administrative expense											(939)
Accounting Standards Update 2014-09 [Member] \| Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Impact on consolidated balance sheet:
Prepaid expense and other current assets	7										7		5
Accumulated deferred income taxes	(13)										(13)		(4)
Other noncurrent assets	31										31		16
Retained deficit	29										29		$ 17
Impact on statement of consolidated income (loss)
Operating revenues											3
Net income (loss)											12
Selling, general and administrative expense											13
Restricted Cash Previously Reported As Source (Use) Of Cash Now Reported In Changes In Cash, Cash Equivalents And Restricted Cash Per ASU 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (decrease) in restricted cash									48			186
Reclassification Of Income Tax Effects Of Tax Cuts And Jobs Act Within Accumulated Other Comprehensive Income To Retained Earnings Per ASU 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adoption of new accounting standard (Note 1)											1
Successor
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adoption of new accounting standard (Note 1)									0		1	0
Impact on statement of consolidated income (loss)
Operating revenues	2,562	$ 3,243	$ 2,574	$ 765	944	$ 1,833	$ 1,296	$ 1,357	1,191		9,144	5,430
Net income (loss)	(186)	$ 331	$ 105	$ (306)	$ (579)	$ 273	$ (26)	$ 78	(163)	$ (163)	(56)	(254)
Selling, general and administrative expense									$ (208)		(926)	$ (600)
Minimum \| Recognition Of Additional Lease Liabilities Per ASU 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease estimated lease liability	230										230
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease estimated lease liability	$ 280										$ 280

Merger Transaction and Business Combination Accounting (Merger Agreement) (Details) - $ / shares		3 Months Ended	12 Months Ended
	Apr. 09, 2018	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Oct. 03, 2016
Common stock, par or stated value per share			$ 0.01		$ 0.01
Exchange Ratio	0.652
Shares issued	94,409,573	427,580,232	97,639,105	818,570
Common stock, shares outstanding	522,932,453	427,580,232	493,215,309	428,398,802	0
Vistra Energy Corp. [Member]
Common stock, par or stated value per share	$ 0.01
Dynegy Inc.
Common stock, par or stated value per share	$ 0.01
Common stock, shares outstanding	144,800,000

Merger Transaction and Business Combination Accounting (Business Combination Narrative) (Details) - USD ($) $ in Millions		9 Months Ended	12 Months Ended
	Apr. 09, 2018	Dec. 31, 2018	Dec. 31, 2018
Business Combinations [Abstract]
Business Combination, Consideration Transferred	$ 2,273
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment	158
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles	(36)
Goodwill, Period Increase (Decrease)	161
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Inventory	(7)
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Accumulated Deferred Income Taxes	101
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Other Noncurrent Assets	(109)
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Trade Accounts Payable and Other Current Liabilities	43
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Other Noncurrent Liabilities	172
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Assets Retirement Obligations, Including Amounts Due Currently	$ 58
Business Combination, Acquisition Related Costs			$ 25
Business Combination, Separately Recognized Transactions, Revenues and Gains Recognized		$ 3,902
Business Combination, Separately Recognized Transactions, Net Gains and Losses		$ 224

Merger Transaction and Business Combination Accounting (Preliminary Purchase Price Allocation) (Details) - USD ($) $ / shares in Units, $ in Millions	Apr. 09, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Oct. 03, 2016
Common stock, shares outstanding	522,932,453	493,215,309	428,398,802	427,580,232	0
Exchange Ratio	0.652
Opening price of Vistra Energy common stock on April 9, 2018	$ 19.87
Purchase price for common stock	$ 1,876
Fair value of equity component of tangible equity units	369
Fair value of outstanding stock compensation awards attributable to pre-combination service	26
Fair value of outstanding warrants	2
Total purchase price	2,273
Preliminary Purchase Price Allocation [Abstract]
Cash and cash equivalents	445
Trade accounts receivables, inventories, prepaid expenses and other current assets	856
Property, plant and equipment	10,520
Accumulated deferred income taxes	492
Identifiable intangible assets	351
Goodwill	161	$ 2,068	$ 1,907
Other noncurrent assets	423
Total assets acquired	13,248
Trade accounts payable and other current liabilities	687
Commodity and other derivative contractual assets and liabilities, net	422
Asset retirement obligations, including amounts due currently	477
Long-term debt, including amounts due currently	8,920
Other noncurrent liabilities	464
Total liabilities assumed	10,970
Identifiable net assets acquired	2,278
Noncontrolling interest in subsidiary	5
Total purchase price	$ 2,273
Vistra Energy Corp. [Member]
Vistra Energy shares issued for Dynegy shares outstanding (in millions)	94,400,000
Dynegy Inc.
Common stock, shares outstanding	144,800,000

Merger Transaction and Business Combination Accounting (Unaudited Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Business Combinations [Abstract]
Revenues	$ 10,595	$ 10,509
Net income (loss)	(268)	(969)
Net loss attributable to Vistra Energy	$ (265)	$ (983)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — basic	$ (0.52)	$ (1.83)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — diluted	$ (0.52)	$ (1.83)

Acquisition and Development of Generation Facilities (Battery Energy Storage Projects) (Details) - Vistra Energy Corp. [Member] $ in Millions	1 Months Ended
	Oct. 31, 2018 USD ($) Megawatt-hour	Jun. 30, 2018 Megawatt-hour
Upton County 2 Solar Facility (Battery Storage Project) [Member] [Member]
Texas Emissions Reduction Plan, Grant Awarded \| $	$ 1
Electricity Generation Facility Capacity	10
Moss Landing Power Plant (Battery Storage Project) [Member]
Electricity Generation Facility Capacity		300
Proposed Contract, Duration, Number Of Years		20 years

Acquisition and Development of Generation Facilities (Odessa Acquisition) (Details) - Successor - Odessa-Ector Power Partners, L.P. [Member] - La Frontera Holdings, LLC [Member] $ in Millions	1 Months Ended
	Aug. 31, 2017 USD ($)	Aug. 01, 2017 Megawatt-hour
Electricity Generation Facility Capacity \| Megawatt-hour		1,054
Purchase And Sale Agreement, Aggregate Purchase Price	$ 355
Earn-Out Provision, Initial Fair Value Included In Purchase Price	$ 16

Acquisition and Development of Generation Facilities (Upton Solar Development) (Details) $ in Millions	12 Months Ended		20 Months Ended
	Dec. 31, 2018 USD ($) Megawatt-hour	Dec. 31, 2017 USD ($)	Dec. 31, 2018 USD ($) Megawatt-hour
Payments to Acquire Productive Assets \| $	$ 34	$ 190	$ 231
Successor \| Luminant Generation Company LLC [Member] \| Upton County 2 Solar Facility [Member]
Electricity Generation Facility Capacity \| Megawatt-hour	180		180

Acquisition and Development of Generation Facilities (Lamar and Forney Acquisition) (Details) - Predecessor - La Frontera Holdings, LLC [Member] $ in Millions	1 Months Ended
	Apr. 30, 2016 USD ($) Megawatt-hour	Apr. 04, 2016 Megawatt-hour
Business Combination, Plant Specific Discount Rate Used To Fair Value Acquired Property, Percent	9.00%
Texas Competitive Electric Holdings Company LLC [Member] \| Debtor-In-Possession Facility [Member] \| Senior Secured Revolving Credit Facility [Member]
Proceeds from Lines of Credit	$ 1,100
Repayments of Lines of Credit	$ 230
Texas Competitive Electric Holdings Company LLC [Member] \| La Frontera Ventures, LLC [Member]
Number Of Natural Gas Fueled Generation Facilities Purchased \| Megawatt-hour	2
Electricity Generation Facility Capacity \| Megawatt-hour		3,000
Purchase And Sale Agreement, Aggregate Purchase Price	$ 1,313
Purchase And Sale Agreement, Repayment Of Existing Project Financing At Closing	950
Purchase And Sale Agreement, Cash And Net Working Capital	$ 236

Acquisition and Development of Generation Facilities (Schedule of Assets Acquired and Liabilities Assumed) (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Apr. 30, 2016	Oct. 02, 2016	Dec. 31, 2017	Apr. 09, 2018	Apr. 04, 2016
Cash paid to seller at close			$ 355
Cash and cash equivalents				$ 445
Property, plant and equipment — net				10,520
Other assets				423
Total assets acquired				13,248
Trade accounts payable and other liabilities				464
Total liabilities assumed				$ 10,970
Predecessor
Cash paid to seller at close		$ 0
Predecessor \| La Frontera Holdings, LLC [Member]
Cash paid to seller at close	$ 603
Net working capital adjustments	(4)
Consideration paid to seller	599
Cash paid to repay project financing at close	950
Total cash paid related to acquisition	$ 1,549
Cash and cash equivalents					$ 210
Property, plant and equipment — net					1,316
Commodity and other derivative contractual assets					47
Other assets					44
Total assets acquired					1,617
Commodity and other derivative contractual liabilities					53
Trade accounts payable and other liabilities					15
Total liabilities assumed					68
Identifiable net assets acquired					$ 1,549

Acquisition and Development of Generation Facilities (Pro Forma Financial Information) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017
Statement [Line Items]
Revenues		$ 10,595	$ 10,509
Net income (loss)		$ (268)	$ (969)
Predecessor \| La Frontera Holdings, LLC [Member]
Statement [Line Items]
Revenues	$ 4,116
Net income (loss)	$ 22,835

Disposition of Generation Facilities (Retirement of Generation Facilities) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Aug. 31, 2018 Megawatt-hour	May 31, 2018 Megawatt-hour power_plant	Feb. 28, 2018 Megawatt-hour power_plant
Northeastern Power Cogeneration Facility [Member]
Electricity generation facility capacity retired		51
Killen Station [Member]
Electricity generation facility capacity retired			204
Jointly owned utility plant, proportionate ownership share			33.00%
J.M. Stuart Station [Member]
Electricity generation facility capacity retired			679
Jointly owned utility plant, proportionate ownership share			39.00%
Killen and J.M. Stuart Stations [Member]
Electricity generation facility capacity retired			883
Number of electric generation plants retired \| power_plant			2
Monticello Steam Electric Station [Member]
Electricity generation facility capacity retired				1,880
Number of electric generation units retired				3
Sandow Steam Electric Station Units 4 and 5 [Member]
Electricity generation facility capacity retired				1,137
Number of electric generation units retired				2
Big Brown Steam Electric Station [Member]
Electricity generation facility capacity retired				1,150
Number of electric generation units retired				2
Monticello, Sandow and Big Brown Steam Electric Stations [Member]
Electricity generation facility capacity retired				4,167
Number of electric generation plants retired \| power_plant				3
Number of electric generation units retired				7
Charges associated with retirement of generation facilities \| $	$ 206
Vistra Energy Corp. [Member] \| Alcoa Corporation and Alcoa USA Corp. [Member]
Proceeds from contract termination \| $	$ 238

Emergence From Chapter 11 Cases (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Oct. 31, 2017	Jun. 30, 2017	Dec. 31, 2018	Oct. 03, 2016
Schedule of Reorganization Costs [Line Items]
Fresh-Start Adjustment, Increase (Decrease), Liabilities Subject to Compromise				$ 33,800
Bankruptcy Claim, Held In Escrow Account To Settle Claims Postconfirmation			$ 52
Chapter 11 Cases, Held In Escrow To Pay Professional Fees Postconfirmation			$ 5
EFH Corp. [Member] \| Internal Revenue Service (IRS) [Member]
Schedule of Reorganization Costs [Line Items]
Alternative Minimum Tax Liability				$ 14
Vistra Energy Corp. [Member] \| EFH Corp. [Member]
Schedule of Reorganization Costs [Line Items]
Tax Matters Agreement Obligation To Reimburse Counterparty For Alternative Minimum Tax Liability Percent				50.00%
Tax Matters Agreement, Reimbursement To Counterparty To Settle Alternative Minimum Tax Liability	$ (3)	$ (7)

Emergence From Chapter 11 Cases (Reorganization Items) (Details) - USD ($) $ in Millions		9 Months Ended
	Oct. 03, 2016	Oct. 02, 2016
Gain on reorganization adjustments	$ (24,252)
Other	$ (14)
Predecessor
Gain on reorganization adjustments		$ (24,252)
Loss from the adoption of fresh start reporting		2,013
Expenses related to legal advisory and representation services		55
Expenses related to other professional consulting and advisory services		39
Contract claims adjustments		13
Other		11
Total reorganization items		$ (22,121)

Fresh-Start Reporting (Reorganization Value Narrative) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Fresh-start reporting criteria, maximum voting shares of predecessor receiving voting shares of successor (percent)	50.00%
Business enterprise value	$ 10,500
Discount rate used to determine enterprise value (percent)	7.00%
Successor
Business enterprise value	$ 10,500
Vistra Energy reorganization value of assets	$ 15,161

Fresh-Start Reporting (Estimate of Reorganization Value of Assets) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Business enterprise value	$ 10,500
Successor
Business enterprise value	10,500
Cash excluded from business enterprise value	1,594
Deferred asset related to prepaid capital lease obligation	38
Current liabilities, excluding short-term portion of debt and capital leases	1,123
Noncurrent, non-interest bearing liabilities	1,906
Vistra Energy reorganization value of assets	$ 15,161

Fresh-Start Reporting (Adjustments to Balance Sheet Including Impact of Plan of Reorganization and Fresh-Start Reporting) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Reorganization Adjustments
Cash and cash equivalents	$ (1,028)
Restricted cash	131
Trade accounts receivable — net	4
Advances to parents and affiliates of Predecessor	(78)
Other current assets	17
Total current assets	(954)
Advance to parent and affiliates of Predecessor	(21)
Investments	1
Property, plant and equipment — net	53
Identifiable intangible assets — net	4
Deferred income taxes	320
Other noncurrent assets	38
Total assets	(559)
Long-term debt due currently	5
Trade accounts payable	145
Trade accounts and other payables to affiliates of Predecessor	(152)
Accrued income taxes	12
Accrued taxes other than income	4
Accrued interest	(109)
Other current liabilities	170
Total current liabilities	75
Long-term debt, less amounts due currently	3,476
Borrowings under debtor-in-possession credit facilities	(3,387)
Liabilities subject to compromise	(33,749)
Deferred income taxes	(256)
Tax Receivable Agreement obligation	574
Other noncurrent liabilities and deferred credits	117
Total liabilities	(33,150)
Common stock	4
Additional paid-in-capital	7,737
Accumulated other comprehensive income (loss)	22
Predecessor membership interests	24,828
Total equity	32,591
Total liabilities and equity	(559)
Fresh-Start Adjustments
Inventories	(86)
Other current assets	3
Total current assets	(83)
Advance to parent and affiliates of Predecessor	4
Investments	9
Property, plant and equipment — net	(5,970)
Goodwill	1,755
Identifiable intangible assets — net	2,256
Commodity and other derivative contractual assets	(14)
Deferred income taxes	730
Other noncurrent assets	158
Total assets	(1,155)
Long-term debt due currently	(1)
Trade accounts payable	3
Other current liabilities	5
Total current liabilities	7
Long-term debt, less amounts due currently	151
Commodity and other derivative contractual liabilities	3
Asset retirement obligations	854
Other noncurrent liabilities and deferred credits	(900)
Total liabilities	115
Accumulated other comprehensive income (loss)	10
Predecessor membership interests	(1,280)
Total equity	(1,270)
Total liabilities and equity	(1,155)
Stockholders' Equity (Vistra Energy)
Total equity	7,741
Predecessor
Current assets (TCEH):
Cash and cash equivalents	1,829
Restricted cash	12
Trade accounts receivable — net	750
Advances to parents and affiliates of Predecessor	78
Inventories	374
Commodity and other derivative contractual assets	255
Margin deposits related to commodity contracts	42
Other current assets	47
Total current assets	3,387
Restricted cash	650
Advance to parent and affiliates of Predecessor	17
Investments	1,038
Property, plant and equipment — net	10,359
Goodwill	152
Identifiable intangible assets — net	1,148
Commodity and other derivative contractual assets	73
Other noncurrent assets	51
Total assets	16,875
Current liabilities (TCEH):
Long-term debt due currently	4
Trade accounts payable	402
Trade accounts and other payables to affiliates of Predecessor	152
Commodity and other derivative contractual liabilities	125
Margin deposits related to commodity contracts	64
Accrued income taxes	12
Accrued taxes other than income	119
Accrued interest	110
Other current liabilities	243
Total current liabilities	1,231
Borrowings under debtor-in-possession credit facilities	3,387
Liabilities subject to compromise	33,749
Commodity and other derivative contractual liabilities	5
Deferred income taxes	256
Asset retirement obligations	809
Other noncurrent liabilities and deferred credits	1,018
Total liabilities	40,455
Equity (TCEH):
Accumulated other comprehensive income (loss)	(32)
Predecessor membership interests	(23,548)
Total equity	(23,580)
Total liabilities and equity	16,875
Successor
Current Assets (Vistra Energy):
Cash and cash equivalents	801
Restricted cash	143
Trade accounts receivable — net	754
Inventories	288
Commodity and other derivative contractual assets	255
Margin deposits related to commodity contracts	42
Other current assets	67
Total current assets	2,350
Restricted cash	650
Investments	1,048
Property, plant and equipment — net	4,442
Goodwill	1,907
Identifiable intangible assets — net	3,408
Commodity and other derivative contractual assets	59
Deferred income taxes	1,050
Other noncurrent assets	247
Total assets	15,161
Current Liabilities (Vistra Energy)
Long-term debt due currently	8
Trade accounts payable	550
Commodity and other derivative contractual liabilities	125
Margin deposits related to commodity contracts	64
Accrued income taxes	24
Accrued taxes other than income	123
Accrued interest	1
Other current liabilities	418
Total current liabilities	1,313
Long-term debt, less amounts due currently	3,627
Commodity and other derivative contractual liabilities	8
Tax Receivable Agreement obligation	574
Asset retirement obligations	1,663
Other noncurrent liabilities and deferred credits	235
Total liabilities	7,420
Stockholders' Equity (Vistra Energy)
Common stock	4
Additional paid-in-capital	7,737
Total equity	7,741
Total liabilities and equity	$ 15,161

Fresh-Start Reporting (Plan of Reorganization Adjustments to Cash and Cash Equivalents) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Net proceeds from PrefCo preferred stock sale	$ 69
Addition of cash balances from the Contributed EFH Debtors	22
Payments to extinguish claims of TCEH first lien creditors	(486)
Cash distributed for TCEH unsecured claims	(502)
Payment of administrative claims to TCEH creditors	(53)
Payment of legal fees, professional fees and other costs (including $52 million to escrow)	(78)
Net use of cash	(1,028)
Payment To TCEH Unsecured Creditors [Member]
Escrow deposit	73
Payment Of Legal Fees, Professional Fees And Other Costs [Member]
Escrow deposit	$ 52

Fresh-Start Reporting (Plan of Reorganization Adjustments Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2018	Oct. 03, 2016
Reorganizations [Abstract]
Reclassification from Liabilities Subject To Compromise to other current assets related to secured and unsecured claims		$ 82
Reclassification from accounts payable to other current liabilities related to accrued professional fees		16
Accrued change-in-control obligation (current)		23
Accrued success fees triggered by Emergence		26
Accrued professional fees (current)		7
Accrued liabilities related to the contributed entities (current)		28
Payments of professional fees		(12)
Borrowings under debtor-in-possession credit facilities		(3,387)
Preferred stock of PrefCo		70
Assumption of benefit plan liabilities associated with pension and health and welfare plans		122
Settlement of life Insurance costs with affiliate		$ 7
Shares of Vistra Energy common stock issued to TCEH first lien creditors		427,500,000
Par value of Vistra Energy common shares issued to TCEH first lien creditors	$ 0.01	$ 0.01

Fresh-Start Reporting (Plan of Reorganization Adjustments to Liabilities Subject to Compromise) (Details) - USD ($) $ in Millions		9 Months Ended
	Oct. 03, 2016	Oct. 02, 2016
Fair value of equity issued to TCEH first lien creditors	$ (7,741)
TRA Rights issued to TCEH first lien creditors	(574)
Cash distributed and accruals for TCEH first lien creditors	(377)
Cash distributed for TCEH unsecured claims	(502)
Cash distributed and accruals for TCEH administrative claims	(60)
Settlement of affiliate balances	(99)
Net liabilities of contributed entities and other items	(60)
Gain on extinguishment of LSTC	24,344
Predecessor
Notes, loans and other debt	31,668
Accrued interest on notes, loans and other debt	646
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements	1,243
Trade accounts payable and other expected allowed claims	192
Third-party liabilities subject to compromise	33,749
LSTC from the Contributed EFH Entities	8
Total liabilities subject to compromise	$ 33,757
Cash distributed for TCEH unsecured claims		$ (429)
Gain on extinguishment of LSTC		$ 24,344

Fresh-Start Reporting (Plan of Reorganization Adjustments to Equity) (Details) $ / shares in Units, $ in Millions	Oct. 03, 2016 USD ($) $ / shares shares
Enterprise value	$ 10,500
Accrual for post-Emergence claims satisfaction	(181)
Tax Receivable Agreement obligation	(574)
Preferred stock of PrefCo	(70)
Other items	(2)
Total equity	$ 7,741
Shares outstanding at October 3, 2016 (in millions) \| shares	427,500,000
Per share value \| $ / shares	$ 18.11
Senior Secured Term Loan B-1 Facility [Member]
Vistra Operations Credit Facility – Term Facility	$ (2,871)
Senior Secured Term Loan C Facility [Member]
Vistra Operations Credit Facility – Term Facility	(655)
Successor
Enterprise value	10,500
Cash and cash equivalents	801
Restricted cash	793
Total equity	7,741
Common stock at par value	4
Additional paid-in-capital	$ 7,737

Fresh-Start Reporting (Plan of Reorganization Adjustments to Membership Interests) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Reorganizations [Abstract]
Gain on extinguishment of LSTC	$ 24,344
Accumulated other comprehensive income (loss)	(22)
Change in control payments	(23)
Professional fees	(33)
Other	(14)
Pretax gain on reorganization adjustments	24,252
Deferred tax impact of the Plan of Reorganization and Spin-off	576
Total impact to membership interests	$ 24,828

Fresh-Start Reporting (Fresh-Start Adjustments Narrative) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Fresh-start adjustment, increase in fair value of certain real property	$ 12
Fresh-start adjustment, reduction in fair value of other investments	(3)
Fresh-start adjustment, identifiable intangible assets	2,256
Fresh-start adjustment, reduction in intangible liabilities	(476)
Fresh-start adjustment, reduction in intangible liabilities (electricity supply contract)	525
Fresh-start adjustment, increase in intangible liabilities (wholesale contracts)	(49)
Fresh-start adjustment, addition of regulatory asset	197
Fresh-start adjustment, removal of unamortized debt issuance costs	(26)
Fresh-start adjustment, increase in fair value of credit facility	151
Fresh start adjustment, reduction of nuclear decommissioning fund excess over asset retirement obligation	(465)
Fresh-start adjustment, increase in fair value of obligations related to leased property	29
Fresh-start adjustment, increase in fair value of pension and OPEB obligations	12
Retail trade names (not subject to amortization) [Member]
Fresh-start adjustment, identifiable intangible assets	270
Retail customer relationship [Member]
Fresh-start adjustment, identifiable intangible assets	1,636
Electricity supply contract [Member]
Fresh-start adjustment, identifiable intangible assets	190
Retail and wholesale contracts [Member]
Fresh-start adjustment, identifiable intangible assets	164
Other Identifiable Intangible Assets [Member]
Fresh-start adjustment, identifiable intangible assets	$ (4)

Fresh-Start Reporting (Fresh-Start Adjustments to Property, Plant and Equipment) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Fresh-Start Adjustment
Generation plants and mining assets	$ (6,057)
Land	140
Nuclear Fuel	(23)
Other equipment	(30)
Total property, plant and equipment	(5,970)
Successor
Fair Value
Generation plants and mining assets	3,698
Land	490
Nuclear Fuel	157
Other equipment	97
Total property, plant and equipment	$ 4,442

Fresh-Start Reporting (Fresh-Start Adjustments to Goodwill) (Details) $ in Millions	Oct. 03, 2016 USD ($)
Business enterprise value	$ 10,500
Successor
Business enterprise value	10,500
Add: Fair value of liabilities excluded from enterprise value	3,030
Less: Fair value of tangible assets	(8,215)
Less: Fair value of identified intangible assets	(3,408)
Goodwill	$ 1,907

Revenue (Revenue Disaggregated By Major Source) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		$ 9,797
Operating revenues	$ 1,191	9,144	$ 5,430
Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		4,426
Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,123
Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		3,126
Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		698
Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		424
Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(43)
Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(610)
Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		0
Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(653)
Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		203
Operating revenues		(2,399)
Intersegment Eliminations [Member] \| Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Intersegment Eliminations [Member] \| Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Intersegment Eliminations [Member] \| Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		167
Intersegment Eliminations [Member] \| Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		30
Intersegment Eliminations [Member] \| Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		6
Intersegment Eliminations [Member] \| Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		0
Intersegment Eliminations [Member] \| Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		7
Intersegment Eliminations [Member] \| Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(2,609)
Intersegment Eliminations [Member] \| Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(2,602)
Retail Segment [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		5,549
Operating revenues		5,597
Retail Segment [Member] \| Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		4,426
Retail Segment [Member] \| Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,123
Retail Segment [Member] \| Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Retail Segment [Member] \| Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Retail Segment [Member] \| Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Retail Segment [Member] \| Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(26)
Retail Segment [Member] \| Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		74
Retail Segment [Member] \| Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		0
Retail Segment [Member] \| Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		48
ERCOT Segment [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,365
Operating revenues		2,634
ERCOT Segment [Member] \| Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
ERCOT Segment [Member] \| Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
ERCOT Segment [Member] \| Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,151
ERCOT Segment [Member] \| Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
ERCOT Segment [Member] \| Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		214
ERCOT Segment [Member] \| Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(1)
ERCOT Segment [Member] \| Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(362)
ERCOT Segment [Member] \| Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		1,632
ERCOT Segment [Member] \| Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		1,269
PJM Segment [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,190
Operating revenues		1,725
PJM Segment [Member] \| Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
PJM Segment [Member] \| Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
PJM Segment [Member] \| Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		792
PJM Segment [Member] \| Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		369
PJM Segment [Member] \| Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		29
PJM Segment [Member] \| Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		2
PJM Segment [Member] \| Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(62)
PJM Segment [Member] \| Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		595
PJM Segment [Member] \| Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		535
NY/NE Segment [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		826
Operating revenues		817
NY/NE Segment [Member] \| Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
NY/NE Segment [Member] \| Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
NY/NE Segment [Member] \| Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		544
NY/NE Segment [Member] \| Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		240
NY/NE Segment [Member] \| Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		42
NY/NE Segment [Member] \| Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(9)
NY/NE Segment [Member] \| Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(41)
NY/NE Segment [Member] \| Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		41
NY/NE Segment [Member] \| Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(9)
MISO Segment [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		606
Operating revenues		720
MISO Segment [Member] \| Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
MISO Segment [Member] \| Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
MISO Segment [Member] \| Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		420
MISO Segment [Member] \| Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		53
MISO Segment [Member] \| Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		133
MISO Segment [Member] \| Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(9)
MISO Segment [Member] \| Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(195)
MISO Segment [Member] \| Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		318
MISO Segment [Member] \| Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		114
Asset Closure Segment [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		58
Operating revenues		50
Asset Closure Segment [Member] \| Retail Energy Charge In ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Asset Closure Segment [Member] \| Retail Energy Charge In Northeast/Midwest [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Asset Closure Segment [Member] \| Wholesale Generation Revenue From ERCOT [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		52
Asset Closure Segment [Member] \| Capacity Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		6
Asset Closure Segment [Member] \| Revenue From Other Wholesale Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0
Asset Closure Segment [Member] \| Retail Contract Amortization [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		0
Asset Closure Segment [Member] \| Hedging And Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(31)
Asset Closure Segment [Member] \| Affiliate Sales [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		23
Asset Closure Segment [Member] \| Total Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues		(8)
Operating revenues [Member]
Disaggregation of Revenue [Line Items]
Unrealized mark-to-market net losses on interest rate swaps		$ (380)

Revenue (Contract and Other Customer Acquisition Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Selling, General and Administrative Expenses [Member]
Capitalized Contract Cost [Line Items]
Capitalized Contract Cost, Amortization	$ 10
Operating revenues [Member]
Capitalized Contract Cost [Line Items]
Capitalized Contract Cost, Amortization	7
Costs To Acquire Residential And Business Retail Customers [Member]
Capitalized Contract Cost [Line Items]
Capitalized Contract Cost, Net	$ 38	$ 22

Revenue (Performance Obligations) (Details) $ in Millions	Dec. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 968
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 718
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 720
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 342
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 38
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 65
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	5 years

Revenue (Accounts Receivable) (Details) $ in Millions	Dec. 31, 2018 USD ($)
Trade accounts receivable - net	$ 1,087
Trade Accounts Receivable From Contracts With Customers [Member]
Trade accounts receivable - net	951
Other Trade Accounts Receivables [Member]
Trade accounts receivable - net	$ 136

Goodwill And Identifiable Intangible Assets (Goodwill) (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Apr. 09, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill		$ 2,068	$ 161	$ 1,907
Retail Segment [Member]
Goodwill [Line Items]
Goodwill		1,907
Successor \| Retail Segment [Member]
Goodwill [Line Items]
Goodwill, Expected Tax Deductible Amount		$ 1,686
Goodwill, Expected Tax Deductible Term	15 years

Goodwill And Identifiable Intangible Assets (Identifiable Intangible Assets Reported in the Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 2,378	$ 2,018
Accumulated Amortization	1,134	717
Total identifiable intangible assets subject to amortization, net	1,244	1,301
Total identifiable intangible assets	2,493	2,530
Retail trade names (not subject to amortization) [Member]
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount, Unamortized Intangibles	1,245	1,225
Mineral interests (not currently subject to amortization) [Member]
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount, Unamortized Intangibles	4	4
Retail customer relationship [Member]
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	1,680	1,648
Accumulated Amortization	876	572
Total identifiable intangible assets subject to amortization, net	804	1,076
Software and other technology-related assets [Member]
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	270	183
Accumulated Amortization	105	47
Total identifiable intangible assets subject to amortization, net	165	136
Retail and wholesale contracts [Member]
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	316	154
Accumulated Amortization	138	87
Total identifiable intangible assets subject to amortization, net	178	67
Contractual Service Agreements [Member]
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	70	0
Accumulated Amortization	0	0
Total identifiable intangible assets subject to amortization, net	70	0
Other Identifiable Intangible Assets [Member]
Finite-Lived and Indefinite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	42	33
Accumulated Amortization	15	11
Total identifiable intangible assets subject to amortization, net	$ 27	$ 22

Goodwill And Identifiable Intangible Assets (Identifiable Intangible Liabilities Reported in Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Schedule of Finite-Lived Intangible Liabilities [Line Items]
Finite-Lived Intangible Liabilities, Net	$ 401	$ 36
Contractual Service Agreements [Member]
Schedule of Finite-Lived Intangible Liabilities [Line Items]
Finite-Lived Intangible Liabilities, Net	136	0
Purchase And Sales Contracts [Member]
Schedule of Finite-Lived Intangible Liabilities [Line Items]
Finite-Lived Intangible Liabilities, Net	195	36
Environmental allowances and credits [Member]
Schedule of Finite-Lived Intangible Liabilities [Line Items]
Finite-Lived Intangible Liabilities, Net	$ 70	$ 0

Goodwill And Identifiable Intangible Assets (Amortization Expense Related to Identifiable Intangible Assets) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017
Successor
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets And Liabilities	$ 203		$ 467	$ 532
Successor \| Depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	162		$ 370	463
Successor \| Retail customer relationship [Member] \| Depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets and Liabilities, Weighted Average Useful Life			4 years
Amortization of Intangible Assets And Liabilities	152		$ 304	420
Successor \| Software and other technology-related assets [Member] \| Depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets and Liabilities, Weighted Average Useful Life			3 years
Amortization of Intangible Assets And Liabilities	9		$ 62	38
Successor \| Retail and wholesale contracts [Member] \| Operating revenues, fuel, purchased power costs and delivery fees [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets and Liabilities, Weighted Average Useful Life			4 years
Amortization of Intangible Assets And Liabilities	38		$ 43	59
Successor \| Other Identifiable Intangible Assets [Member] \| Operating revenues, fuel, purchased power costs and delivery fees, depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets and Liabilities, Weighted Average Useful Life			4 years
Amortization of Intangible Assets And Liabilities	$ 4		$ 58	$ 15
Predecessor
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets And Liabilities		$ 59
Predecessor \| Depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets		58
Predecessor \| Retail customer relationship [Member] \| Depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets And Liabilities		9
Predecessor \| Software and other technology-related assets [Member] \| Depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets And Liabilities		44
Predecessor \| Retail and wholesale contracts [Member] \| Operating revenues, fuel, purchased power costs and delivery fees [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets And Liabilities		0
Predecessor \| Other Identifiable Intangible Assets [Member] \| Operating revenues, fuel, purchased power costs and delivery fees, depreciation and amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets And Liabilities		$ 6

Goodwill And Identifiable Intangible Assets (Estimated Amortization of Identifiable Intangible Assets and Liabilities) (Details) $ in Millions	Dec. 31, 2018 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2019	$ 299
2020	201
2021	154
2022	91
2023	$ 67

Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017
Deferred:
Income tax expense (benefit)	$ (70)		$ (45)	$ 504
Successor
Current:
U.S. Federal	0		(13)	72
State	6		30	14
Total current	6		17	86
Deferred:
U.S. Federal	(75)		(8)	417
State	(1)		(54)	1
Total deferred	(76)		(62)	418
Income tax expense (benefit)	$ (70)		$ (45)	$ 504
Predecessor
Current:
U.S. Federal		$ (6)
State		9
Total current		3
Deferred:
U.S. Federal		(1,234)
State		(36)
Total deferred		(1,270)
Income tax expense (benefit)		$ (1,267)

Income Taxes (Reconciliation of Income Taxes Computed at the U.S. Federal Statutory Rate to Income Tax Expense (Benefit) Recorded (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017
Income (loss) before income taxes		$ (233)		$ (101)	$ 250
Effective tax rate at federal statutory rate		35.00%	35.00%	21.00%	35.00%
Income tax expense (benefit)		$ (70)		$ (45)	$ 504
Successor
Income (loss) before income taxes		(233)		(101)	250
Income taxes at the U.S. federal statutory rate		(82)		(20)	88
Nondeductible TRA accretion		5		8	(80)
State tax, net of federal benefit		3		22	13
Impacts of tax reform legislation on deferred taxes	$ 451	0		0
Return to provision adjustment		0		(12)	19
Remeasurement of historical Vistra Energy deferred taxes for expanded state footprint		0		(54)	0
Effect of refundable minimum tax credits no longer subject to sequestration		0		(15)	0
Nondeductible compensation		0		8	0
Nondeductible transaction costs		0		3	0
Equity awards		0		(3)	0
Nondeductible debt restructuring costs		2		0	0
Nondeductible interest expense		0		0	0
Nontaxable gain on extinguishment of LSTC		0		0	0
Valuation allowance on state NOLs		0		20	0
Other		2		(2)	13
Income tax expense (benefit)		$ (70)		$ (45)	$ 504
Effective tax rate		30.00%		44.60%	201.60%
Predecessor
Income (loss) before income taxes			$ 21,584
Income taxes at the U.S. federal statutory rate			7,554
Nondeductible TRA accretion			0
State tax, net of federal benefit			(21)
Impacts of tax reform legislation on deferred taxes			0
Return to provision adjustment			0
Remeasurement of historical Vistra Energy deferred taxes for expanded state footprint			0
Effect of refundable minimum tax credits no longer subject to sequestration			0
Nondeductible compensation			0
Nondeductible transaction costs			0
Equity awards			0
Nondeductible debt restructuring costs			38
Nondeductible interest expense			12
Nontaxable gain on extinguishment of LSTC			(8,593)
Valuation allowance on state NOLs			(210)
Other			(47)
Income tax expense (benefit)			$ (1,267)
Effective tax rate			(5.90%)

Income Taxes (Deferred Income Tax Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Noncurrent Deferred Income Tax Assets
Tax credit carryforwards	$ 76	$ 0
Loss carryforwards	958	0
Property, plant and equipment	0	520
Identifiable intangible assets	184	81
Long-term debt	188	20
Employee benefit obligations	109	56
Commodity contracts and interest rate swaps	212	25
Other	40	8
Total deferred tax assets	1,767	710
Property, plant and equipment	406	0
Total deferred tax liabilities	406	0
Valuation allowance	35	0
Net deferred tax assets	1,326	$ 710
State of Illinois
Noncurrent Deferred Income Tax Assets
Valuation allowance	20
Other Jurisdictions [Member]
Noncurrent Deferred Income Tax Assets
Valuation allowance	$ 15

Income Taxes (Income Tax Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Net deferred tax assets	$ 1,326	$ 710
Operating loss carryforwards	3,560
Alternative minimum tax credits	255
Tax effects of the components included in accumulated other comprehensive loss, deferred tax assets	$ 2
Tax effects of the components included in accumulated other comprehensive income, deferred tax liabilities		$ (6)

Income Taxes (Accounting for Uncertainty in Income Taxes) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Jul. 31, 2016	Dec. 31, 2016	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017	Oct. 03, 2016	Dec. 31, 2015
Predecessor
Income Tax Examination [Line Items]
Unrecognized Tax Benefits				$ 0				$ 36
Settlements with taxing authorities				$ (35)
Predecessor \| Texas Comptroller Of Public Accounts [Member]
Income Tax Examination [Line Items]
Tax payment related to settlement with taxing authority, net	$ 12
Settlements with taxing authorities	$ (27)
Predecessor \| Internal Revenue Service (IRS) [Member] \| Tax Years 2010 through 2013 [Member]
Income Tax Examination [Line Items]
Settlements with taxing authorities		$ (1)
Income tax payments assessed but not paid		$ 15
Successor
Income Tax Examination [Line Items]
Unrecognized Tax Benefits			$ 0		$ 39	$ 0	$ 0
Settlements with taxing authorities			$ 0		$ 0	$ 0

Income Taxes (Summary of Uncertain Tax Positions) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017
Successor
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period, excluding interest and penalties			$ 0	$ 0
Additions based allocated in the Merger	$ 0		39	0
Reductions based on tax positions related to prior years	0		0	0
Settlements with taxing authorities	0		0	0
Balance at end of period, excluding interest and penalties	0		$ 39	$ 0
Predecessor
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period, excluding interest and penalties	$ 0	$ 36
Additions based allocated in the Merger		0
Reductions based on tax positions related to prior years		(1)
Settlements with taxing authorities		(35)
Balance at end of period, excluding interest and penalties		$ 0

Tax Receivable Agreement Obligation (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017	Oct. 03, 2016
Additions (reductions) to Tax Receivable Agreement obligation				$ 14	$ (295)
Effective tax rate at federal statutory rate		35.00%	35.00%	21.00%	35.00%
Estimated undiscounted future payments under Tax Receivable Agreement				$ 1,400
Estimated future tax payments under Tax Receivables Agreement, approximate amount attributable to first fifteen tax years after Emergence (percent)				50.00%
Impacts of tax receivable agreement		$ (22)		$ (79)	$ 213
Successor
Percent of cash tax savings due Tax Receivable Agreement Rights Holders				85.00%
Tax receivable agreement obligation	$ 357	596		$ 420	357	$ 574
Impacts of tax receivable agreement	$ (117)	(22)		(79)	213
Payments		0		16	26
Accretion expense		$ 22		$ 65	$ 82

Tax Receivable Agreement Obligation (Summary of Tax Receivables Agreement Obligation) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Noncurrent TRA obligation at the end of the period		$ 420	$ 333
Successor
TRA obligation at the beginning of the period		357	596
Accretion expense	$ 22	65	82
Payments	0	(16)	(26)
Changes in tax assumptions impacting timing of payments	0	14	(62)
Revaluation due to tax reform legislation	0	0	(233)
TRA obligation at the beginning of the period	596	420	357
Less amounts due currently	0	0	(24)
Noncurrent TRA obligation at the end of the period	$ 596	$ 420	$ 333

Interest Expense and Related Charges (Interest Expense and Related Charges) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 02, 2016	Dec. 31, 2018	Dec. 31, 2017
Interest Expense and Related Charges [Line Items]
Total interest expense and related charges	$ 60		$ 572	$ 193
Successor
Interest Expense and Related Charges [Line Items]
Interest paid/accrued post-Emergence	51		537	213
Interest paid/accrued on debtor-in-possession financing	0		0	0
Adequate protection amounts paid/accrued	0		0	0
Unrealized mark-to-market net (gains) losses on interest rate swaps	11		5	(29)
Amortization of debt issuance costs, discounts and premiums	(1)		0	4
Debt extinguishment loss	0		27	0
Capitalized interest	(3)		(12)	(7)
Other	2		15	12
Total interest expense and related charges	$ 60		$ 572	$ 193
Predecessor
Interest Expense and Related Charges [Line Items]
Interest paid/accrued post-Emergence		$ 0
Interest paid/accrued on debtor-in-possession financing		76
Adequate protection amounts paid/accrued		977
Unrealized mark-to-market net (gains) losses on interest rate swaps		0
Amortization of debt issuance costs, discounts and premiums		4
Debt extinguishment loss		0
Capitalized interest		(9)
Other		1
Total interest expense and related charges		$ 1,049
Line of Credit [Member] \| Vistra Operations Company LLC [Member] \| Successor
Interest Expense and Related Charges [Line Items]
Debt Instrument, Interest Rate During Period			4.24%	4.38%

Interest Expense and Related Charges (Contractual Interest Expense on Pre-Petition Liabilities) (Details) - Predecessor $ in Millions	9 Months Ended
	Oct. 02, 2016 USD ($)
Contractual Interest Expense On Pre-Petition Liabilities [Line Items]
Adequate Protection Interest Paid-Accrued, Amount Excluded Related To Terminated Natural Gas Hedging Positions And Interest Rate Swaps	$ 47
Contractual interest on debt classified as LSTC	1,570
Adequate protection amounts paid/accrued	930
Contractual interest on debt classified as LSTC not paid/accrued	$ 640
Adequate Protection Interest Expense [Member]
Contractual Interest Expense On Pre-Petition Liabilities [Line Items]
Adequate Protection Paid Or Accrued, Weighted Average Interest Rate	4.95%

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Net loss attributable to Vistra Energy										$ (54)
Successor
Net loss attributable to Vistra Energy	$ (186)	$ 330	$ 108	$ (306)	$ (579)	$ 273	$ (26)	$ 78	$ (163)	$ (54)	$ (254)
Weighted average shares of common stock outstanding - basic									427,560,620	504,954,371	427,761,460
Net loss per weighted average share of common stock outstanding - basic	$ (0.35)	$ 0.62	$ 0.21	$ (0.71)	$ (1.35)	$ 0.64	$ (0.06)	$ 0.18	$ (0.38)	$ (0.11)	$ (0.59)
Weighted average shares of common stock outstanding - diluted									427,560,620	504,954,371	427,761,460
Net loss per weighted average share of common stock outstanding - diluted	$ (0.35)	$ 0.61	$ 0.20	$ (0.71)	$ (1.35)	$ 0.64	$ (0.06)	$ 0.18	$ (0.38)	$ (0.11)	$ (0.59)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									7,332,789	14,165,813	3,642,844

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

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The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

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