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, 2017, 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 $7 million in escrow to pay remaining professional fees incurred in the Chapter 11 Cases. The remaining contingent and/or disputed claims against the TCEH Debtors consist primarily of unsecured legal claims, including asbestos claims. These remaining claims and the related escrow balance for the claims are recorded in Vistra Energy's 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 and the year ended December 31, 2015, respectively, as reported in the statements of consolidated income (loss):



	Predecessor
	Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
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			141
Expenses related to other professional consulting and advisory services	39			69
Contract claims adjustments	13			54
Noncash adjustment for estimated allowed claims related to debt	—			896
Adjustment to affiliate claims pursuant to Settlement Agreement (Note 19)	—			(635		)
Gain on settlement of debt held by affiliates (Note 19)	—			(382		)
Gain on settlement of interest on debt held by affiliates	—			(20		)
Sponsor management agreement settlement	—			(19		)
Contract assumption adjustments	—			(14		)
Fees associated with extension/completion of the DIP Facility	—			9
Other	11			2
Total reorganization items	$	(22,121	)	$	101

Fresh-Start Reporting (Notes)

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [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 12 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 9 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 17 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 14.


(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 7).

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 21 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

(Goodwill And Identifiable Intangible Assets) (Notes)

12 Months Ended

Dec. 31, 2017

Goodwill And Identifiable Intangible Assets

GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The carrying value of goodwill totaled $1.907 billion at both December 31, 2017 and 2016. The goodwill arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to the Retail Electricity reporting unit (see Note 1). Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.

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 the Retail Electricity reporting unit exceeded its carrying value at October 1, 2017. 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.

Predecessor Goodwill Impairments

During the fourth quarter of 2015, our Predecessor performed a goodwill impairment analysis as of its annual testing date of December 1. Further, during the fourth quarter of 2015, there were significant declines in the market values of several similarly situated peer companies with publicly traded equity, which indicated our Predecessor's overall enterprise value should be reassessed. Our Predecessor's testing resulted in an impairment of goodwill of $800 million at December 1, 2015.

During the first nine months of 2015, our Predecessor experienced impairment indicators related to decreases in forward wholesale electricity prices when compared to those prices reflected in its December 1, 2014 goodwill impairment testing analysis. As a result, the likelihood of goodwill impairments had increased, and our Predecessor initiated further testing of goodwill. Our Predecessor's testing of goodwill for impairment during the first nine months of 2015 resulted in impairment charges totaling $1.4 billion.

Identifiable Intangible Assets

Identifiable intangible assets are comprised of the following:



	December 31, 2017						December 31, 2016
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	1,648	$	572	$	1,076	$	1,648	$	152	$	1,496
Software and other technology-related assets	183		47		136		147		9		138
Electricity supply contract (a)	—		—		—		190		2		188
Retail and wholesale contracts	154		87		67		164		38		126
Other identifiable intangible assets (b)	33		11		22		30		2		28
Total identifiable intangible assets subject to amortization	$	2,018	$	717	1,301		$	2,179	$	203	1,976
Retail trade names (not subject to amortization)					1,225						1,225
Mineral interests (not currently subject to amortization)					4						4
Total identifiable intangible assets					$	2,530					$	3,205

____________


(a)	Contract terminated in October 2017. See Note 4.


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

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



			Successor				Predecessor
Identifiable Intangible Asset	Statements of Consolidated Income (Loss) Line	Remaining useful lives at December 31, 2017 (weighted average in years)	Year Ended December 31, 2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Retail customer relationship	Depreciation and amortization	4	$	420	$	152	$	9	$	17
Software and other technology-related assets	Depreciation and amortization	3	38		9		44		60
Electricity supply contract	Operating revenues	0	6		2		—		—
Retail and wholesale contracts	Operating revenues/fuel, purchased power costs and delivery fees	3	59		38		—		—
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	4	9		2		6		30
Total amortization expense (a)			$	532	$	203	$	59	$	107

____________


(a)	Amounts recorded in depreciation and amortization totaled $463 million, $162 million, $58 million and $85 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

Following is a description of the separately identifiable intangible assets. In connection with fresh start reporting (see Note 6), the intangible assets were adjusted based on their estimated fair value as of the Effective Date, based on observable prices or estimates of fair value using valuation models.

•

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 and 4Change Energy^TM 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 TXU Energy's and 4Change Energy's 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, 2017.

•

Electricity supply contract – The electricity supply contract represents a long-term fixed-price supply contract for the sale of electricity from one of our generation facilities that was measured at fair value at Emergence. The value of this contract under our Predecessor was recorded as an unfavorable liability due to prevailing market prices of electricity when the contract was established in 2007. Significant assumptions included in the fair value measurement for this contract include long-term wholesale electricity price forecasts and operating cost forecasts for the respective generation facility. This contract was terminated in October 2017. See Note 4.

•

Retail and wholesale contracts – These intangible assets represent the favorable value of various retail and wholesale contracts (both purchase and sale contracts) that were measured at fair value by utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The value of these contracts is being amortized using a method that is based on the monthly value of each contract measured at Emergence.

Estimated Amortization of Identifiable Intangible Assets

As of December 31, 2017, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2018	$	367
2019	$	268
2020	$	191
2021	$	142
2022	$	4

Predecessor Intangible Impairments

The impairments of generation facilities in 2015 (see Note 4) resulted in the impairment of the SO₂ allowances under the Clean Air Act's acid rain cap-and-trade program that are associated with those facilities to the extent they are not projected to be used at other sites. The fair market values of the SO₂ allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 15). Our Predecessor also impaired certain of its SO₂allowances under the Cross-State Air Pollution Rule (CSAPR) related to the impaired generation facilities. Accordingly, in the year ended December 31, 2015, our Predecessor recorded noncash impairment charges of $55 million (before deferred income tax benefit) in other deductions (see Note 21) related to its existing environmental allowances and credits intangible asset. SO₂emission allowances granted under the acid rain cap-and-trade program were recorded as intangible assets at fair value in connection with purchase accounting in 2007. Additionally, the impairments of generation and related mining facilities in 2015 resulted in recording noncash impairment charges of $19 million (before deferred income tax benefit) in other deductions (see Note 21) related to mine development costs (included in other identifiable intangible assets in the table above) at the facilities.

During 2015, our Predecessor determined that certain intangible assets related to favorable power purchase contracts should be evaluated for impairment. That conclusion was based on declines in wholesale electricity prices in ERCOT experienced during 2015. The fair value measurement was based on a discounted cash flow analysis of the contracts that compared the contractual price and terms of the contract to forecasted wholesale electricity and renewable energy credit (REC) prices in ERCOT. As a result of the analysis, our Predecessor recorded a noncash impairment charge of $8 million (before deferred income tax benefit) in other deductions (see Note 21).

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Taxes

INCOME TAXES

Subsequent to the Effective Date, the TCEH Debtors and the Contributed EFH Debtors are included in Vistra Energy's consolidated federal income tax return and are no longer included in the consolidated federal income tax return of EFH Corp.

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, 2017		Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Current:
U.S. Federal	$	72	$	—		$	(6	)	$	(17	)
State	14		6			9			21
Total current	86		6			3			4
Deferred:
U.S. Federal	417		(75		)	(1,234		)	(811		)
State	1		(1		)	(36		)	(72		)
Total deferred	418		(76		)	(1,270		)	(883		)
Total	$	504	$	(70	)	$	(1,267	)	$	(879	)

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



	Successor						Predecessor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Income (loss) before income taxes	$	250		$	(233	)	$	21,584		$	(5,556	)
Income taxes at the U.S. federal statutory rate of 35%	88			(82		)	7,554			(1,945		)
Nondeductible TRA accretion	(80		)	5			—			—
Texas margin tax, net of federal benefit	13			3			(21		)	—
Impacts of tax reform legislation on deferred taxes	451			—			—			—
Effects of Tax Matters Agreement and tax-free spin-off transaction	19			—			—			—
Nondeductible debt restructuring costs	—			2			38			64
Nondeductible interest expense	—			—			12			21
Nontaxable gain on extinguishment of LSTC	—			—			(8,593		)	—
Valuation allowance	—			—			(210		)	210
Nondeductible goodwill impairment	—			—			—			770
Lignite depletion allowance	—			—			—			(8		)
Interest accrued for uncertain tax positions, net of tax	—			—			—			(2		)
Other	13			2			(47		)	11
Income tax expense (benefit)	$	504		$	(70	)	$	(1,267	)	$	(879	)
Effective tax rate	201.6		%	30.0		%	(5.9		)%	15.8		%

Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2017 and 2016 are as follows:



	December 31,
	2017		2016
Noncurrent Deferred Income Tax Assets
Net operating loss (NOL) carryforwards	$	—	$	8
Property, plant and equipment	520		943
Intangible assets	81		29
Long-term debt	20		52
Employee benefit obligations	56		84
Commodity contracts and interest rate swaps	25		—
Other	8		6
Total deferred tax assets	$	710	$	1,122

At December 31, 2017, we had total deferred tax assets of approximately $710 million that were substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment. Our deferred tax assets were significantly impacted by the TCJA that was signed into law in December 2017, which reduced the overall federal corporate rate from 35% to 21%. This rate change decreased our overall deferred tax asset balance by approximately $451 million. As of December 31, 2017, 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 that analysis, we concluded that it is more likely than not that the deferred tax assets would be fully utilized by future taxable income, and thus, no valuation allowance was recognized.

At December 31, 2017, we had no net operating loss (NOL) carryforwards for federal income tax purposes. At December 31, 2017, we had no alternative minimum tax (AMT) credit carryforwards available.

The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax asset of $6 million at December 31, 2017 and a net deferred tax liability of $3 million at December 31, 2016.

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.

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 has limited operational history and filed its first federal tax return in October 2017. Vistra Energy is not currently under audit for any period, and we had no uncertain tax positions at both December 31, 2017 and 2016.

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. Examinations of income tax returns filed by EFH Corp. and any of its subsidiaries for the years ending prior to January 1, 2015 are complete. The IRS chose not to audit the tax return filed by EFH Corp. for the 2015 tax year. 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 is currently in progress and is expected to conclude by 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.

In June 2015, EFH Corp. signed a RAR with the IRS for the 2008 and 2009 tax years. The Bankruptcy Court approved EFH Corp.'s signing of the RAR in July 2015. As a result of EFH Corp. signing this RAR, our Predecessor reduced the liability for uncertain tax positions by $22 million, resulting in a $18 million increase in noncurrent inter-company tax payable to EFH Corp., a $2 million reclassification to the accumulated deferred income tax liability and the recording of a $2 million income tax benefit. Total cash payment to be assessed by the IRS for tax years 2008 and 2009, but not paid during the pendency of the Chapter 11 Cases of the EFH Debtors, is approximately $15 million, plus any interest that may be assessed.

Our Predecessor classified interest and penalties related to uncertain tax positions as current income tax expense. Ongoing accruals of interest after the IRS settlements were not material in 2015.

Noncurrent liabilities of our Predecessor included a total of $4 million in accrued interest at December 31, 2015. The federal income tax benefit on the interest accrued on uncertain tax positions was recorded as accumulated deferred income taxes.

The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheets, during the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively:



	Predecessor
	Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Balance at beginning of period, excluding interest and penalties	$	36		$	65
Reductions based on tax positions related to prior years	(1		)	(11		)
Settlements with taxing authorities	(35		)	(18		)
Balance at end of period, excluding interest and penalties	$	—		$	36

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, 2017

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 TCEH. The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in 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 Lamar and Forney Acquisition in April 2016 (see Note 3) and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.

Pursuant to the TRA, we issued the TRA Rights for the benefit of the first lien secured creditors of our Predecessor entitled to receive such TRA Rights under the Plan. Such TRA Rights are subject to various transfer restrictions described in the TRA and are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 19).

During the year ended December 31, 2017, we recorded reductions to the carrying value of the TRA obligation totaling approximately $295 million. The largest driver in the reduction to the TRA obligation carrying value primarily resulted from a change in the corporate tax rate from 35% to 21% related to tax reform legislation, which reduced the total expected undiscounted payments under the TRA from $2.1 billion to $1.2 billion. The value of the TRA obligation was also impacted by changes in the estimated timing of TRA payments resulting from changes in certain tax assumptions including (a) the impacts of Luminant's plan to retire its Monticello, 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 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 year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016:



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

As of December 31, 2017, the estimated carrying value of the TRA obligation totaled $357 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% 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. Our estimates of taxable income did not consider the impact of the Merger. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. The aggregate amount of undiscounted payments under the TRA is estimated to be approximately $1.2 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 (assuming that the TRA is not terminated earlier pursuant to its terms).

The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation. During the 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 and payments of $26 million net of 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.

Under the Internal Revenue Code, a corporation's ability to utilize certain tax attributes, including depreciation, may be limited following an ownership change if the corporation's overall asset tax basis exceeds the overall fair market value of its assets (after making certain adjustments). The Spin-Off resulted in an ownership change and it is expected that the overall tax basis of our assets may have exceeded the overall fair market value of our assets at such time. As a result, there may be a limitation on our ability to claim a portion of our depreciation deductions for a five-year period. This limitation could have a material impact on our tax liabilities and on our obligations under the TRA Rights. In addition, any future ownership change of Vistra Energy following Emergence could likewise result in additional limitations on our ability to use certain tax attributes existing at the time of any such ownership change and have an impact on our tax liabilities and on our obligations with respect to the TRA Rights under the TRA.

Interest Expense and Related Charges

12 Months Ended

Dec. 31, 2017

Interest Expense and Related Charges [Abstract]

Interest Expense and Related Charges

INTEREST EXPENSE AND RELATED CHARGES



	Successor						Predecessor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Interest paid/accrued post-Emergence	$	213		$	51		$	—		$	—
Interest paid/accrued on debtor-in-possession financing	—			—			76			63
Adequate protection amounts paid/accrued	—			—			977			1,233
Unrealized mark-to-market net (gains) losses on interest rate swaps	(29		)	11			—			—
Capitalized interest	(7		)	(3		)	(9		)	(11		)
Other	16			1			5			4
Total interest expense and related charges	$	193		$	60		$	1,049		$	1,289

Successor

Interest expense and related charges totaled $193 million and $60 million for the Successor for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively. The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 12, was 4.38% and 4.78% at December 31, 2017 and 2016, respectively.

Predecessor

Interest expense for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015 reflects interest paid and accrued on debtor-in-possession financing (see Note 12) 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 and the year ended December 31, 2015 was 4.95% and 4.69%, respectively.

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 and $897 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively, which had been stayed by the Bankruptcy Court effective on the Petition Date. Adequate protection amounts paid/accrued presented below excludes interest paid/accrued on TCEH first-lien interest rate and commodity hedge claims totaling $47 million and $60 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively, as such amounts are not included in contractual interest amounts below.



	Predecessor
	Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Contractual interest on debt classified as LSTC	$	1,570	$	2,070
Adequate protection amounts paid/accrued	930		1,173
Contractual interest on debt classified as LSTC not paid/accrued	$	640	$	897

Earnings Per Share (Notes)

12 Months Ended

Dec. 31, 2017

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, 2017							Period from October 3, 2016 through December 31, 2016
	Net Loss			Shares	Per Share Amount			Net Loss			Shares	Per Share Amount
Net loss available for common stock — basic	$	(254	)	427,761,460	$	(0.59	)	$	(163	)	427,560,620	$	(0.38	)
Net loss available for common stock — diluted	$	(254	)	427,761,460	$	(0.59	)	$	(163	)	427,560,620	$	(0.38	)

For the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, stock-based incentive compensation plan awards totaling 3,642,844 and 7,332,789 shares, respectively, were excluded from the calculation of diluted earnings per share because the effect would have been antidilutive.

Long-Term Debt

12 Months Ended

Dec. 31, 2017

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, 2017			December 31, 2016
Vistra Operations Credit Facilities (a)	$	4,323		$	4,515
Mandatorily redeemable subsidiary preferred stock (b)	70			70
8.82% Building Financing due semiannually through February 11, 2022 (c)	30			36
Capital lease obligations	—			2
Total long-term debt including amounts due currently	4,423			4,623
Less amounts due currently	(44		)	(46		)
Total long-term debt less amounts due currently	$	4,379		$	4,577

____________

(a)

At December 31, 2017, borrowings under the Vistra Operations Credit Facilities in our consolidated balance sheet include debt premiums of $21 million, debt discounts of $2 million and debt issuance costs of $7 million. At December 31, 2016, borrowings under the Vistra Operations Credit Facilities in our consolidated balance sheet include debt premiums of $25 million, debt discounts of $2 million and debt issuance costs of $8 million.


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


(c)	Obligation related to a corporate office space capital lease 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.

Vistra Operations Credit Facilities — At December 31, 2017, the Vistra Operations Credit Facilities consisted of up to $5.171 billion in senior secured, first lien revolving credit commitments and outstanding term loans, consisting of revolving credit commitments of up to $860 million (Revolving Credit Facility), initial term loans in the amount totaling $2.821 billion (Initial Term Loan B Facility), incremental term loans totaling $990 million (Incremental Term Loan B Facility, and together with the Initial Term Loan B Facility, the Term Loan B Facility) and letter of credit term loans totaling $500 million (Term Loan C Facility). Principal amounts repaid on the Term Loan B Facility and the Term Loan C Facility cannot be reborrowed. Also in December 2017, although the size of the Revolving Credit Facility did not change, the letter of credit sub-facility of the Revolving Credit Facility was increased from $600 million to $715 million.

The Vistra Operations Credit Facilities and related available capacity at December 31, 2017 are presented below.



		December 31, 2017
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity
Revolving Credit Facility (a)	August 4, 2021	$	860	$	—	$	834
Initial Term Loan B Facility (b)(c)	August 4, 2023	2,850		2,821		—
Incremental Term Loan B Facility (c)	December 14, 2023	1,000		990		—
Term Loan C Facility (d)	August 4, 2023	650		500		7
Total Vistra Operations Credit Facilities		$	5,360	$	4,311	$	841

___________


(a)	Facility to be used for general corporate purposes. Facility includes a $715 million letter of credit sub-facility, of which $26 million of letters of credit were outstanding at December 31, 2017.


(b)	Facility used to repay all amounts outstanding under our Predecessor's DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes.


(c)	Cash borrowings under the Term Loan B Facility reflect required scheduled quarterly payment in annual amount equal to 1% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed.

(d)

Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in our consolidated balance sheets. Cash borrowings reflect a $150 million principal reduction paid from restricted cash in December 2017. Amounts paid cannot be reborrowed. At December 31, 2017, the restricted cash supported $493 million in letters of credit outstanding (see Note 21), leaving $7 million in available letter of credit capacity.

In February, August and December 2017, certain pricing terms for the Vistra Operations Credit Facility were amended. We accounted for these transactions as modifications of debt. At December 31, 2017, cash borrowings under the Revolving Credit Facility bore interest based on applicable LIBOR rates, plus a fixed spread of 2.50%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bore interest of 2.50%. Amounts borrowed under the Initial Term Loan B Facility and the Term Loan C Facility bore interest based on applicable LIBOR rates, subject to a 0.75% floor, plus a fixed spread of 2.50%. Amounts borrowed under the Incremental Term Loan B Facility bore interest based on applicable LIBOR rates, subject to a 0.75% floor, plus a fixed spread of 2.75%. At December 31, 2017, the weighted average interest rate before taking into consideration interest rate swaps on outstanding borrowings was 4.02%, 4.20% and 3.83% under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility, respectively. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available Vistra Operations Credit Facilities.

In February 2018, certain pricing terms for the Vistra Operations Credit Facility were amended. Any amounts borrowed under the Revolving Credit Facility will bear interest based on applicable LIBOR rates plus 2.25%. Letters of credit issued under the Revolving Credit Facility will bear interest of 2.25%. Amounts borrowed under the Incremental Term Loan B Facility will bear interest based on applicable LIBOR rates plus 2.25%.

Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities.

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

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

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $100 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. Although the period ended December 31, 2017 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

Maturities — Long-term debt maturities at December 31, 2017 are as follows:



	December 31, 2017
2018	$	44
2019	44
2020	44
2021	45
2022	42
Thereafter	4,189
Unamortized premiums, discounts and debt issuance costs	15
Total long-term debt, including amounts due currently	$	4,423

Interest Rate Swaps — In the Successor period from October 3, 2016 through December 31, 2016, we entered into $3.0 billion notional amount of interest rate swaps to hedge a portion of our exposure to our variable rate debt. The interest rate swaps, which became effective in January 2017, expire in July 2023 and effectively fix the interest rates between 4.50% and 4.88% on $3.0 billion of our variable rate debt. The interest rate swaps are secured by a first lien secured interest on a pari passu basis with the Vistra Operations Credit Facilities.

Predecessor

DIP Roll Facilities — In August 2016, the Predecessor entered into the DIP Roll Facilities. The facilities provided for up to $4.250 billion in senior secured, super-priority financing. The DIP Roll Facilities were senior, secured, super-priority debtor-in-possession credit agreements by and among the TCEH Debtors, the lenders that were party thereto from time to time and an administrative and collateral agent. On the Effective Date, the DIP Roll Facilities converted to the Vistra Operations Credit Facilities discussed above. Net proceeds from the DIP Roll Facilities 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, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2017, we had contractual commitments under energy-related contracts, leases and other agreements as follows.



	Coal purchase and transportation agreements		Pipeline transportation and storage reservation fees		Nuclear Fuel Contracts		Other Contracts
2018	$	12	$	39	$	120	$	158
2019	—		28		48		46
2020	—		28		47		55
2021	—		29		55		36
2022	—		29		32		89
Thereafter	—		141		193		194
Total	$	12	$	294	$	495	$	578

Amounts in other contracts include certain long-term service and maintenance contracts related to our generation assets. 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 $416 million, $109 million, $139 million and $218 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

At December 31, 2017, future minimum lease payments under operating leases are as follows:



	Operating Leases (a)
2018	$	17
2019	15
2020	12
2021	10
2022	8
Thereafter	150
Total future minimum lease payments	$	212

___________


(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 $69 million, $20 million, $39 million and $55 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

Guarantees

We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2017, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees.

Letters of Credit

At December 31, 2017, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $519 million as follows:


•	$390 million to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ERCOT;


•	$45 million to support executory contracts and insurance agreements;


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


•	$29 million for other credit support requirements.

Litigation

Litigation Related to EPA Reviews — In June 2008, the EPA issued an initial request for information to Luminant under the EPA's authority under Section 114 of the Clean Air Act (CAA). The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, Luminant received an additional information request from the EPA under Section 114 related to our Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to our Sandow 4 generation facility.

In July 2012, the EPA sent Luminant a notice of violation alleging noncompliance with the CAA's New Source Review standards and the air permits at our Martin Lake and Big Brown generation facilities. In August 2013, the 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 New Source Review standards, at our Big Brown and Martin Lake generation facilities. In August 2015, the district court granted Luminant's motion to dismiss seven of the nine claims asserted by the EPA in the lawsuit. In August 2016, the EPA filed an amended complaint, eliminating one of the two remaining claims and withdrawing with prejudice a request for civil penalties in the other remaining claim. The EPA also filed a motion for entry of final judgment so that it could seek to appeal the district court's dismissal decision. In September 2016, Luminant filed a response opposing the EPA's motion for entry of final judgment. In October 2016, the district court denied the EPA's motion for entry of final judgment and agreed that the remaining claim must be fully adjudicated at the district court or withdrawn with prejudice before the EPA may appeal the dismissal decision.

In January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in Luminant's favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) and Luminant filed a motion in the district court to recover its attorney fees and costs. In April 2017, the district court stayed its consideration of Luminant's motion for attorney fees. In June 2017, the EPA and the Sierra Club filed their opening briefs in the Fifth Circuit Court. Luminant filed its response brief in August 2017. In September 2017, the EPA and the Sierra Club filed their reply briefs. The case has been set for oral argument at the Fifth Circuit Court in March 2018. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. The lawsuit requests the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time or retirement of the remaining plant, Martin Lake, at issue and could possibly require the payment of substantial penalties. The recent 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.

Greenhouse Gas Emissions

In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed and existing electricity generation units, referred to as the Clean Power Plan. The rule for existing facilities would establish state-specific emissions rate goals to reduce nationwide CO₂ emissions related to affected units by over 30% from 2012 emission levels by 2030. A number of parties, including Luminant, filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) for the rule for new, modified and reconstructed plants. In addition, a number of petitions for review of the rule for existing plants were filed in the D.C. Circuit Court by various parties and groups, including challenges from twenty-seven different states opposed to the rule as well as those from, among others, certain power generating companies, various business groups and some labor unions. Luminant also filed its own petition for review. In January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the 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.

In March 2017, President Trump issued an Executive Order entitled Promoting Energy Independence and Economic Growth (Order). The Order covers a number of matters, including the Clean Power Plan. Among other provisions, the Order directs the EPA to review the Clean Power Plan and, if appropriate, suspend, revise or rescind the rules on existing and new, modified and reconstructed generating units. In April 2017, in accordance with the Order, the EPA published its intent to review the Clean Power Plan. In addition, the DOJ has filed motions seeking to abate those cases until the EPA concludes its review of the rules, including any new rulemaking that results from that review. In April 2017, the D.C. Circuit Court issued orders holding the cases in abeyance for 60 days and directing the EPA to provide status reports at 30-day intervals. The D.C. Circuit Court further ordered that all parties file supplemental briefs in May 2017 on whether the cases should be remanded to the EPA rather than held in abeyance. The D.C. Circuit Court entered additional 60-day abeyances in August 2017 and November 2017. The latest 60-day abeyance expired in January 2018, and the D.C. Circuit Court has yet to take further action on the EPA's request to continue the abeyance. In October 2017, the EPA issued a proposed rule that would repeal the Clean Power Plan. The proposed repeal focuses on what the EPA believes to be the unlawful nature of the Clean Power Plan and asks for public comment on the EPA's interpretations of its authority under the Clean Air Act. We currently plan to submit comments in response to the proposed repeal by April 2018. 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. We currently plan on submitting comments by the February 2018 deadline. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately implemented or upheld as they were issued, they could have a material impact on our results of operations, liquidity or financial condition.

Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO₂) and nitrogen oxide (NO_X) emissions from our fossil fueled generation units. In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In June 2012, the EPA finalized the proposed rule (Second Revised Rule).

The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the Supreme Court to consider further legal challenges, the D.C. Circuit Court ruled in favor of Luminant and other petitioners, holding that the CSAPR emissions budgets over-controlled Texas and other states. The D.C. Circuit Court remanded those states' budgets to the EPA for prompt reconsideration. While Luminant planned to participate in the EPA's reconsideration process to develop increased budgets for the 1997 ozone standard that do not over-control Texas, the EPA instead responded to the remand by proposing a new rulemaking that created new NO_X ozone season budgets for the 2008 ozone standard without addressing the over-controlling budgets for the 1997 standard. Comments on the EPA's proposal were submitted by Luminant in February 2016. In August 2016, the EPA disapproved certain aspects of Texas's infrastructure State Implementation Plan (SIP) for the 2008 ozone National Ambient Air Quality Standard and imposed a Federal Implementation Plan (FIP) in its place in October 2016. Texas filed a petition in the Fifth Circuit Court challenging the SIP disapproval and Luminant intervened in support of Texas's challenge. The parties moved to stay the case and the court responded by dismissing the petition with the right to reinstate as provided in the Fifth Circuit Court's rules. The State of Texas and Luminant have also both filed challenges in the D.C. Circuit Court challenging the EPA's FIP and those cases are currently pending before that court. With respect to Texas's SO₂ emission budgets, in June 2016, the EPA issued a memorandum describing the EPA's proposed approach for responding to the D.C. Circuit Court's remand for reconsideration of the CSAPR SO₂ emission budgets for Texas and three other states that had been remanded to the EPA by the D.C. Circuit Court. In the memorandum, the EPA stated that those four states could either voluntarily participate in the CSAPR by submitting a SIP revision adopting the SO₂ budgets that had been previously held invalid by the D.C. Circuit Court and the current annual NO_X budgets or, if the state chooses not to participate in the CSAPR, the EPA could withdraw the CSAPR FIP by the fall of 2016 for those states and address any interstate transport and regional haze obligations on a state-by-state basis. Texas has not indicated that it intends to adopt the over-controlling budgets and, in November 2016, the EPA proposed to withdraw the CSAPR FIP addressing SO₂ and NOx for Texas. In September 2017, the EPA finalized its proposal to remove Texas from the annual CSAPR programs. The Sierra Club and the National Parks Conservation Association filed a petition for review in the D.C. Circuit Court challenging that final rule. Luminant has intervened on behalf of the EPA. As a result of the EPA's action, Texas electric generating units are no longer subject to the CSAPR annual SO₂ and NO_X limits, but remain subject to the CSAPR's ozone season NO_X requirements. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA's recent actions concerning the CSAPR annual emissions budgets for affected states participating in the CSAPR program, based upon our current operating plans, including the recent retirements of our Monticello, Big Brown and Sandow 4 plants (see Note 4), we do not believe that the CSAPR itself will cause any material operational, financial or compliance issues to our business or require us to incur any material compliance costs.

Regional Haze — Reasonable Progress and Long-Term Strategies

The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas, like national parks, which impairment results from man-made pollution." There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. In February 2009, the TCEQ submitted a SIP concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the Clean Air Interstate Rule (CAIR) instead of the EPA's replacement CSAPR program that the EPA finalized in July 2011. The EPA finalized the limited disapproval of Texas's Regional Haze SIP in June 2012. In August 2012, Luminant filed a petition for review in the Fifth Circuit Court challenging the EPA's limited disapproval of the Regional Haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court's decision in the CSAPR litigation. In August 2012, Luminant filed a motion to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA's limited disapproval and issuance of a FIP regarding the regional haze best available retrofit technology (BART) program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. Briefing in the D.C. Circuit Court was completed in March 2017, and oral argument was held in November 2017.

In May 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas related to the reasonable progress program. After releasing a proposed rule in November 2014 and receiving comments from a number of parties, including Luminant and the State of Texas in April 2015, the EPA issued a final rule in January 2016 approving in part and disapproving in part Texas' SIP for Regional Haze and issuing a FIP for Regional Haze. In the rule, the EPA asserts that the Texas SIP does not show reasonable progress in improving visibility for two areas in Texas and that its long-term strategy fails to make emission reductions needed to achieve reasonable progress in improving visibility in the Wichita Mountains of Oklahoma. The EPA's emission limits in the FIP assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity generating units and upgrades to existing scrubbers at seven generation units. Specifically, for Luminant, the EPA's FIP is based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4. Under the terms of the rule, subject to the legal proceedings described in the following paragraph, the scrubber upgrades would be required by February 2019, and the new scrubbers would be required by February 2021.

In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the Fifth Circuit Court challenging the FIP's Texas requirements. Luminant and other parties also filed motions to stay the FIP while the court reviews the legality of the EPA's action. In July 2016, the Fifth Circuit Court denied the EPA's motion to dismiss Luminant's challenge to the FIP and denied the EPA's motion to transfer the challenges Luminant, the other industry petitioners and the State of Texas filed to the D.C. Circuit Court. In addition, the Fifth Circuit Court granted the motions to stay filed by Luminant, the other industry petitioners and the State of Texas pending final review of the petitions for review. The case was abated until the end of November 2016 in order to allow the parties to pursue settlement discussions. Settlement discussions were unsuccessful, and in December 2016 the EPA filed a motion seeking a voluntary remand of the rule back to the EPA for further consideration of Luminant's pending request for administrative reconsideration. Luminant and some of the other petitioners filed a response opposing the EPA's motion to remand and filed a cross motion for vacatur of the rule in December 2016. In March 2017, the Fifth Circuit Court remanded the rule back to the EPA for reconsideration in light of the Court's prior determination that we and the other petitioners demonstrated a substantial likelihood that the EPA exceeded its statutory authority and acted arbitrarily and capriciously, but the Court denied all of the other pending motions. The stay of the rule (and the emission control requirements) remains in effect. In addition, the Fifth Circuit Court denied the EPA's motion to lift the stay as to parts of the rule implicated in the EPA's subsequent BART proposal and the Court is retaining jurisdiction of the case and requiring the EPA to file status reports on its reconsideration every 60 days. The recent 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 may have a material impact on our results of operations, liquidity or financial condition.

Regional Haze — Best Available Retrofit Technology

The second part of the Regional Haze Program subjects certain electricity generation units built between 1962 and 1977, to BART standards designed to improve visibility if such units cause or contribute to impairment of visibility in a federal class I area. BART reductions of SO₂ and NO_X are required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CSAPR or other approved alternative program. In response to a lawsuit by environmental groups, the U.S. District Court for the District of Columbia (D.C. District Court) issued a consent decree in March 2012 that required the EPA to propose a decision on the Regional Haze SIP by May 2012 and finalize that decision by November 2012. The consent decree requires a FIP for any provisions that the EPA disapproves. The D.C. District Court has amended the consent decree several times to extend the dates for the EPA to propose and finalize a decision on the Regional Haze SIP. The consent decree was modified in December 2015 to extend the deadline for the EPA to finalize action on the determination and adoption of requirements for BART for electricity generation. Under the amended consent decree, the EPA had until December 2016 to propose, and had until September 2017 to finalize, either approval of the state plan or a FIP for BART for Texas electricity generation sources if the EPA determines that BART requirements have not been met. The EPA issued a proposed BART FIP for Texas in January 2017. The EPA's proposed emission limits assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at 12 electric generation units and upgrades to existing scrubbers at four electric generation units. Specifically, for Luminant, the EPA's proposed emission limitations were based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3 and Monticello Unit 3. Luminant evaluated the requirements and potential financial and operational impacts of the proposed rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale power prices in ERCOT, would challenge the long-term economic viability of those units. Under the terms of the proposed rule, the scrubber upgrades would have been required within three years of the effective date of the final rule and the new scrubbers will be required within five years of the effective date of the final rule. We submitted comments on the proposed FIP in May 2017.

The EPA signed the final BART FIP for Texas in September 2017. The rule is a partial approval of Texas's 2009 SIP and a partial FIP. In response to comments on the proposed rule submitted to the EPA, for SO₂, the rule creates an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating units, including our Martin Lake, Big Brown, Monticello, Sandow 4, Stryker 2 and Graham 2 plants. Of the 39 units, 30 are BART-eligible, three are co-located with a BART-eligible unit and six units are included in the program based on a visibility impacts analysis by the EPA. The 39 units represent 89% of SO₂ emissions from Texas electric generating units in 2016 and 85% of all CSAPR SO₂ allowance allocations for Texas existing electric generating units. The compliance obligations in the program will start on January 1, 2019. The identified units will receive an annual allowance allocation that is equal to their most recent annual CSAPR SO₂ allocation. Luminant's units covered by the program are allocated 91,222 allowances annually. Under the rule, a unit that is listed that does not operate for two consecutive years starting after 2018 would no longer receive allowances after the fifth year of non-operation. We believe the recent 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 electric generating 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. Additionally, the National Parks Conservation Association, the Sierra Club, the Environmental Defense Fund and other environmental groups filed a motion in the D.C. Circuit Court in October 2017 to enforce the terms of the consent decree that was originally entered in 2012. The EPA filed a cross-motion to terminate the consent decree in October 2017. These motions remain pending before the D.C. Circuit Court. Luminant has intervened on behalf of the EPA in that action. While we cannot predict the outcome of the rulemaking and potential legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material impact on our results of operation, liquidity or financial condition.

Intersection of the CSAPR and Regional Haze Programs

Historically the EPA has considered compliance with a regional trading program, such as the CSAPR, as satisfying a state's obligations under the BART portion of the Regional Haze Program. However, in the reasonable progress FIP, the EPA diverged from this approach and did not treat Texas' compliance with the CSAPR as satisfying its obligations under the BART portion of the Regional Haze Program. The EPA concluded that it would not be appropriate to finalize that determination given the remand of the CSAPR budgets. As described above, the EPA has now removed Texas from the annual CSAPR trading programs for SO₂ and NO_X and has issued a final BART FIP for Texas.

Affirmative Defenses During Malfunctions

In February 2013, in response to a petition for rulemaking filed by the Sierra Club, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP that was found to be lawful by the Fifth Circuit Court in 2013. In 2014, as a result of a D.C. Circuit Court decision striking down an affirmative defense in another EPA rule, the EPA revised its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The EPA's revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. In May 2015, the EPA finalized the proposal. In June 2015, Luminant filed a petition for review in the Fifth Circuit Court challenging certain aspects of the EPA's final rule as they apply to the Texas SIP. The State of Texas and other parties have also filed similar petitions in the Fifth Circuit Court. In August 2015, the Fifth Circuit Court transferred the petitions that Luminant and other parties filed to the D.C. Circuit Court, and in October 2015 the petitions were consolidated with the pending petitions challenging the EPA's action in the D.C. Circuit Court. Briefing in the D.C. Circuit Court on the challenges was completed in October 2016 and oral argument was originally set for May 2017. However, in April 2017, the court granted the EPA's motion to continue oral argument and ordered that the case be held in abeyance with the EPA to provide status reports to the court on the EPA's review of the action at 90-day intervals. We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation of the rule as finalized may have a material impact on our results of operations, liquidity or financial condition.

SO2 Designations for Texas

In February 2016, the EPA notified Texas of the EPA's preliminary intention to designate nonattainment areas for counties surrounding our Big Brown, Monticello and Martin Lake generation plants based on modeling data submitted to the EPA by the Sierra Club. Such designation would potentially require the implementation of various controls or other requirements to demonstrate attainment. Luminant submitted comments challenging the use of modeling data rather than data from actual air quality monitoring equipment. In November 2016, the EPA finalized its proposed designations for Texas including finalizing the nonattainment designations for the areas referenced above. In doing so, the EPA ignored contradictory modeling that we submitted with our comments. The final designation mandates would be for Texas to begin the multi-year process to evaluate what potential emission controls or operational changes, if any, may be necessary to demonstrate attainment. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court and protective petitions in the D.C. Circuit Court. In March 2017, the EPA filed a motion to transfer or dismiss our Fifth Circuit Court petition, and the State of Texas and Luminant filed an opposition to that motion. Briefing on that motion in the Fifth Circuit Court was completed in May 2017, and the Fifth Circuit Court held oral argument on that motion in July 2017. In August 2017, the Fifth Circuit Court denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. In October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance in light of the EPA's representation that it intended to revisit the 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 designation for Freestone County and Titus County are based solely on the Sierra Club modeling of alleged SO₂ emissions from Monticello and Big Brown. We dispute the Sierra Club's modeling. Regardless, considering these retirements, the nonattainment designation for those counties are no longer supported. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.

Litigation Related to the Merger

In January 2018, a purported Dynegy stockholder filed a putative class action lawsuit in the U.S. District Court for the Southern Division of Texas, Houston Division, alleging that Dynegy, each member of the Dynegy board of directors and Vistra Energy violated federal securities laws by filing a Form S-4 Registration Statement in connection with the Merger that omits purportedly material information. The lawsuit seeks to enjoin the Merger and to have Dynegy and Vistra Energy issue an amended Form S-4 or, alternatively, damages if the Merger closes without an amended Form S-4 having been filed. Two other related lawsuits were also filed but neither of those named Vistra Energy. In February 2018, Vistra Energy and Dynegy filed supplemental disclosures to the Registration Statement and the plaintiffs agreed to forego any further effort to enjoin the Merger, dismiss the individual claims with prejudice, and dismiss without prejudice claims of the putative class following the stockholder vote scheduled for March 2, 2018.

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 initial term of all collective bargaining agreements covering bargaining unit personnel engaged in lignite mining operations, lignite-, coal- and nuclear-fueled generation operations and some of our natural gas-fueled generation operations expired in March 2017, but remain effective pursuant to evergreen provisions unless and until terminated by either party. Vistra Energy is currently negotiating a new collective bargaining agreement with one of our local unions, while new agreements with our two other local unions have been ratified, but not yet executed. 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 $13.4 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 $13.4 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 $127.3 million. This approximately $127.3 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur in September 2018. Assessments are currently limited to $19 million per operating licensed reactor per year per incident. As of December 31, 2017, our maximum potential assessment under the industry retrospective plan would be approximately $254.6 million per incident but no more than $37.9 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, 2017

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 year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 are reflected in the table below.



	Successor
	Year Ended December 31, 2017	Period from October 3, 2016 through December 31, 2016
Shares outstanding at beginning of period	427,580,232	—
Shares issued (a)	818,570	427,580,232
Shares repurchased	—	—
Shares outstanding at end of period	428,398,802	427,580,232

____________


(a)	Includes share awards granted to directors and other nonemployees.

Dividends — Vistra Energy did not declare or pay any dividends during the year ended December 31, 2017. In December 2016, the board of directors of Vistra Energy 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 Vistra Operations Credit Facilities (the Credit Facilities Agreement) generally restricts the ability of Vistra Operations Company LLC (Vistra Operations) to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2017, Vistra Operations can distribute approximately $1.0 billion to Vistra Energy Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent during the year ended December 31, 2017 of approximately $1.1 billion. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2017, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled $3.9 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 year ended December 31, 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 $(23) million and $6 million, respectively. 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.

Predecessor Membership Interests

TCEH paid no dividends in the period from January 1, 2016 through October 2, 2016 nor the year ended December 31, 2015.

Fair Value Measurements

12 Months Ended

Dec. 31, 2017

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 16 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, 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



December 31, 2016
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	167	$	131	$	98	$	—	$	396
Interest rate swaps	—		5		—		13		18
Nuclear decommissioning trust – equity securities (c)	425		—		—		—		425
Nuclear decommissioning trust – debt securities (c)	—		340		—		—		340
Sub-total	$	592	$	476	$	98	$	13	1,179
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									247
Total assets									$	1,426
Liabilities:
Commodity contracts	$	302	$	15	$	15	$	—	$	332
Interest rate swaps	—		16		—		13		29
Total liabilities	$	302	$	31	$	15	$	13	$	361

____________


(a)	See table below for description of Level 3 assets and liabilities.


(b)	Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our consolidated balance sheets.


(c)	The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets. See Note 21.


(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, coal, fuel oil and uranium agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 16 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, 2017 and 2016:



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 options	—		(91		)	(91		)	Option Pricing Model	Gas to power correlation (e)	30% to 100%
										Power volatility (e)	5% to 180%
Electricity congestion revenue 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	)



December 31, 2016
	Fair Value
Contract Type (a)	Assets		Liabilities			Total		Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	32	$	—		$	32	Valuation Model	Hourly price curve shape (c)	$0 to $35/ MWh
									Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$30 to $70/ MWh
Electricity congestion revenue rights	42		(6		)	36		Market Approach (f)	Illiquid price differences between settlement points (g)	$0 to $10/ MWh
Other (h)	24		(9		)	15
Total	$	98	$	(15	)	$	83

____________


(a)	Electricity purchase and sales contracts include power and heat rate positions in ERCOT regions. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Electricity options consist of physical electricity options and spread options.


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


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


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


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


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


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


(h)	Other includes contracts for natural gas, weather options and coal options. December 31, 2016 also includes an immaterial amount of electricity options.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015. See the table below for discussion of transfers between Level 2 and Level 3 for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015.



	Successor						Predecessor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Net asset balance at beginning of period (a)	$	83		$	81		$	37		$	35
Total unrealized valuation gains (losses)	(136		)	31			122			27
Purchases, issuances and settlements (b):
Purchases	69			15			37			49
Issuances	(22		)	(7		)	(20		)	(13		)
Settlements	(106		)	(30		)	(51		)	(48		)
Transfers into Level 3 (c)	4			3			1			1
Transfers out of Level 3 (c)	71			(10		)	1			(14		)
Earn-out provision (d)	(16		)	—			—			—
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) (e)	—			—			(30		)	—
Net change (f)	(136		)	2			60			2
Net asset (liability) balance at end of period	$	(53	)	$	83		$	97		$	37
Unrealized valuation gains (losses) relating to instruments held at end of period	$	(98	)	$	28		$	98		$	18

____________


(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 year ended December 31, 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 incurred 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 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, 2017

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 15 for a discussion of the fair value of derivatives.

Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets. We also utilize short-term electricity, natural gas, coal, fuel oil and uranium derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our statements of consolidated income (loss) in operating revenues and fuel, purchased power costs and delivery fees in the Successor period and net gain from commodity hedging and trading activities in the Predecessor period.

Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our 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, 2017 and 2016. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.



	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	)



	December 31, 2016
	Derivative Assets					Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps			Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	350	$	—		$	—		$	—		$	350
Noncurrent assets	46		17			—			1			64
Current liabilities	—		(12		)	(330		)	(17		)	(359		)
Noncurrent liabilities	—		—			(2		)	—			(2		)
Net assets (liabilities)	$	396	$	5		$	(332	)	$	(16	)	$	53

At December 31, 2017 and 2016, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects. 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
Derivative (statements of consolidated income (loss) presentation)	Year Ended December 31, 2017		Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Commodity contracts (Operating revenues)	$	56	$	(92	)	$	—	$	—
Commodity contracts (Fuel, purchased power costs and delivery fees)	6		21			—		—
Commodity contracts (Net gain from commodity hedging and trading activities)	—		—			194		380
Interest rate swaps (Interest expense and related charges)	2		(11		)	—		—
Net gain (loss)	$	64	$	(82	)	$	194	$	380

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 and the year ended December 31, 2015. There were no amounts recognized in OCI for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015.

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 certain CME transactions that, beginning in January 2017, are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.

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



	December 31, 2017												December 31, 2016
	Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)			Net Amounts			Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)			Net Amounts
Derivative assets:
Commodity contracts	$	220		$	(113	)	$	(1	)	$	106		$	396		$	(193	)	$	(20	)	$	183
Interest rate swaps	18			—			—			18			5			—			—			5
Total derivative assets	238			(113		)	(1		)	124			401			(193		)	(20		)	188
Derivative liabilities:
Commodity contracts	(316		)	113			1			(202		)	(332		)	193			136			(3		)
Interest rate swaps	—			—			—			—			(16		)	—			—			(16		)
Total derivative liabilities	(316		)	113			1			(202		)	(348		)	193			136			(19		)
Net amounts	$	(78	)	$	—		$	—		$	(78	)	$	53		$	—		$	116		$	169

____________


(a)	Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.


(b)	Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements and, to a lesser extent, initial margin requirements.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at December 31, 2017 and 2016:



	December 31, 2017		December 31, 2016
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	1,259		1,282		Million MMBtu
Electricity	114,129		75,322		GWh
Congestion Revenue Rights (b)	110,913		126,573		GWh
Coal	2		12		Million U.S. tons
Fuel oil	5		34		Million gallons
Uranium	325		25		Thousand pounds
Interest rate swaps – floating/fixed (c)	$	3,000	$	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 ERCOT.


(c)	Includes notional amounts of interest rate swaps that became effective in January 2017 and have maturity dates through July 2023.

Credit Risk-Related Contingent Features of Derivatives

Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

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



	December 31,
	2017			2016
Fair value of derivative contract liabilities (a)	$	(204	)	$	(31	)
Offsetting fair value under netting arrangements (b)	103			13
Cash collateral and letters of credit	41			1
Liquidity exposure	$	(60	)	$	(17	)

____________


(a)	Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).


(b)	Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.

Concentrations of Credit Risk Related to Derivatives

We have concentrations of credit risk with the counterparties to our derivative contracts. At December 31, 2017, total credit risk exposure to all counterparties related to derivative contracts totaled $361 million (including associated accounts receivable). The net exposure to those counterparties totaled $180 million at December 31, 2017 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $63 million. At December 31, 2017, the credit risk exposure to the banking and financial sector represented 34% of the total credit risk exposure and 24% 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, 2017

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.

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, 2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Pension costs	$	6	$	2	$	4	$	8
OPEB costs	6		2		—		3
Total benefit costs recognized as expense	$	12	$	4	$	4	$	11

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 the realized and unrealized 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, 2017 measurement date:



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate	4.31		%	3.79		%
Expected return on plan assets	4.86		%	4.89		%
Expected rate of compensation increase	3.50		%	3.50		%
Components of Net Pension Cost:
Service cost	$	5		$	2
Interest cost	6			1
Expected return on assets	(5		)	(1		)
Net periodic pension cost	$	6		$	2
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss	$	3		$	(4	)
Total recognized in net periodic benefit cost and other comprehensive income	$	9		$	(2	)
Assumptions Used to Determine Benefit Obligations:
Discount rate	3.74		%	4.31		%
Expected rate of compensation increase	3.62		%	3.50		%



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Change in Pension Obligation:
Projected benefit obligation at beginning of period	$	144		$	154
Service cost	5			2
Interest cost	6			1
Actuarial (gain) loss	13			(12		)
Benefits paid	(5		)	(1		)
Projected benefit obligation at end of year	$	163		$	144
Accumulated benefit obligation at end of year	$	157		$	136
Change in Plan Assets:
Fair value of assets at beginning of period	$	117		$	124
Actual gain (loss) on assets	16			(6		)
Benefits paid	(5		)	(1		)
Fair value of assets at end of year	$	128		$	117
Funded Status:
Projected pension benefit obligation	$	(163	)	$	(144	)
Fair value of assets	128			117
Funded status at end of year	$	(35	)	$	(27	)
Amounts Recognized in the Balance Sheet Consist of:
Other current liabilities	$	—		$	—
Other noncurrent liabilities	(35		)	(27		)
Net liability recognized	$	(35	)	$	(27	)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net gain	$	1		$	4

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,
	2017		2016
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations	$	163	$	144
Accumulated benefit obligation	$	157	$	136
Plan assets	$	128	$	117

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:



Asset Category:	Target Allocation Ranges
Fixed income	74	%	-	86%
U.S. equities	8	%	-	14%
International equities	6	%	-	12%

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
Asset Class:	Expected Long-Term Rate of Return
U.S. equity securities	6.4	%
International equity securities	7.3	%
Fixed income securities	3.9	%
Weighted average	4.6	%

Fair Value Measurement of Pension Plan Assets

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



	December 31,
	2017			2016
Asset Category:
Level 2 valuations (see Note 15):
Interest-bearing cash	$	(7	)	$	(4	)
Fixed income securities:
Corporate bonds (a)	65			54
U.S. Treasuries	29			30
Other (b)	7			6
Total assets categorized as Level 2	94			86
Assets measured at net asset value (c):
Interest-bearing cash	2			2
Equity securities:
U.S.	14			14
International	13			9
Fixed income securities:
Corporate bonds (a)	5			6
Total assets measured at net asset value	34			31
Total assets	$	128		$	117

___________


(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, 2017 measurement date:



	Successor
	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)	4.11		%	4.00		%
Discount rate (Oncor Plan)	4.18		%	3.69		%
Components of Net Postretirement Benefit Cost:
Service cost	$	2		$	1
Interest cost	4			1
Plan amendments (a)	—			(4		)
Net periodic OPEB cost (income)	$	6		$	(2	)
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
Net (gain) loss and prior service (credit) cost	$	26		$	(5	)
Total recognized in net periodic benefit cost and other comprehensive income	$	32		$	(7	)
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate (Vistra Energy Plan)	3.67		%	4.11		%
Discount rate (Split-Participant Plan)	3.67		%	—		%
Discount rate (Oncor Plan)	—		%	4.18		%

___________


(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.



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year	$	88		$	97
Service cost	2			1
Interest cost	4			1
Participant contributions	2			1
Plan amendments (a)	11			(4		)
Actuarial (gain) loss	15			(5		)
Benefits paid	(7		)	(3		)
Benefit obligation at end of year	$	115		$	88
Change in Plan Assets:
Fair value of assets at beginning of year	$	—		$	—
Employer contributions	5			1
Participant contributions	2			1
Benefits paid	(7		)	(2		)
Fair value of assets at end of year	$	—		$	—
Funded Status:
Benefit obligation	$	115		$	88
Funded status at end of year	$	115		$	88
Amounts Recognized on the Balance Sheet Consist of:
Other current liabilities	$	6		$	5
Other noncurrent liabilities	109			83
Net liability recognized	$	115		$	88
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss and prior service cost	$	20		$	5

___________


(a)	For the year ended December 31, 2017, plan amendments relate to the contractual arrangement with Oncor covering Split Participants. For the period from October 3, 2016 through December 31, 2016, a curtailment gain was recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees.

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



	Successor
	December 31, 2017		December 31, 2016
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year	7.00	%	5.80	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50	%	5.00	%
Year that the rate reaches the ultimate trend rate	2026		2024
Assumed Health Care Cost Trend Rates-Medicare Advantage Eligible (2017) / Medicare Eligible (2016):
Health care cost trend rate assumed for next year	10.66	%	5.70	%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50	%	5.00	%
Year that the rate reaches the ultimate trend rate	2026		2024



	1-Percentage Point Increase		1-Percentage Point Decrease
Sensitivity Analysis of Assumed Health Care Cost Trend Rates:
Effect on accumulated postretirement obligation	$	2	$	(2	)
Effect on postretirement benefits cost	$	—	$	—

Fair Value Measurement of OPEB Plan Assets

At December 31, 2017, the Vistra Energy OPEB plan had no plan assets.

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 Hewitt AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2017 consisted of 391 corporate bonds with an average rating of AA using Moody's, Standard & Poor's Rating Services and Fitch Ratings, Ltd. ratings.

Amortization in 2018

We estimate amortization of the net actuarial gain for the Retirement Plan from accumulated other comprehensive income into net periodic benefit cost will be immaterial. We estimate amortization of the net actuarial gain and prior service cost for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be $3 million.

Contributions

Successor — 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, and none are expected to be made in 2018. OPEB plan funding for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 totaled $5 million and $1 million, respectively, and funding in 2018 is expected to total $6 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. In December 2015, a cash contribution totaling $67 million was made to the EFH Retirement Plan assets, of which $51 million was contributed by Oncor and $16 million was contributed by our Predecessor. Each of these contributions resulted in the Retirement Plan being fully funded as calculated under the provisions of ERISA. As a result of the Bankruptcy Filing, participants in the EFH Retirement Plan who chose to retire would not be eligible for the lump sum payout option under the EFH Retirement Plan unless the EFH Retirement Plan was fully funded. OPEB plan funding for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015 totaled $3 million and $8 million, respectively.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:



	2018		2019		2020		2021		2022		2023-27
Pension benefits	$	11	$	8	$	8	$	8	$	9	$	50
OPEB	$	6	$	7	$	8	$	8	$	8	$	39

Thrift Plan

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.

Employer contributions to the Thrift Plan totaled $19 million, $5 million, $16 million and $21 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, 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 the purpose of 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.

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



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Total stock-based compensation expense	$	19		$	3
Income tax benefit	(7		)	(1		)
Stock based-compensation expense, net of tax	$	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 of directors of Vistra Energy 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 14).

Stock options outstanding at December 31, 2017 are all held by current employees. The following table summarizes our stock option activity:



	Successor
	Year Ended December 31, 2017
	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	7,357		$	15.81	9.8	$	—
Granted	1,412		$	18.86
Exercised	(281	)	$	13.41
Forfeited or expired	(352	)	$	13.76
Total outstanding at end of period	8,136		$	14.44	9.0	$	32.4
Expected to vest	6,618		$	14.65	9.1	$	25.1

At December 31, 2017, $30 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, 2017
	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	2,159		$	15.79	2.3	$	33.5
Granted	861		$	18.84
Exercised	(538	)	$	15.76
Forfeited or expired	(107	)	$	15.85
Total outstanding at end of period	2,375		$	16.91	1.9	$	43.5
Expected to vest	2,375		$	16.91	1.9	$	43.5

At December 31, 2017, $37 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, 2017, we had not yet established the significant terms of the PSUs relevant to vesting (scorecard and metric design, thresholds, and targets); therefore, a grant date for financial accounting purposes has not occurred.

Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions

RELATED PARTY TRANSACTIONS

Successor

In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.

Registration Rights Agreement

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra Energy common stock held by such selling stockholders.

In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra Energy common stock held by certain significant stockholders pursuant to the Registration Rights Agreement. The registration statement was amended in February 2017, April 2017 and May 2017. The registration statement was declared effective by the SEC in May 2017. Among other things, under the terms of the Registration Rights Agreement:


•	we will be required to use reasonable best efforts to convert the Form S-1 registration statement into a registration statement on Form S-3 as soon as reasonably practicable after we become eligible to do so and to have such Form S-3 declared effective as promptly as practicable (but in no event more than 30 days after it is filed with the SEC);


•	if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and

•

the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra Energy common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed.

All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us. Legal fee expenses paid or accrued by Vistra Energy on behalf of the selling stockholders totaled less than $1 million during the year ended December 31, 2017.

Tax Receivable Agreement

On the Effective Date, Vistra Energy entered into the TRA with a transfer agent on behalf of certain former first lien creditors of TCEH. See Note 9 for discussion of the TRA.

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, a tax matters agreement and a settlement agreement.

The following represent our Predecessor's significant related-party transactions. As of the Effective Date, pursuant to the Plan of Reorganization, the Sponsor Group, EFH Corp., EFIH, Oncor Holdings and Oncor ceased being affiliates of Vistra Energy and its subsidiaries, including the TCEH Debtors and the Contributed EFH Debtors.

•

Our retail operations (and prior to the Effective Date, our Predecessor) pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled $700 million and $955 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

•

A former subsidiary of EFH Corp. billed our Predecessor's subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges, which are largely settled in cash and primarily reported in SG&A expenses, totaled $157 million and $205 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

•

Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to Vistra Energy (and prior to the Effective Date, our Predecessor) for contribution to the trust fund with the intent that the trust fund assets, reported in other investments in our 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 and $17 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively. Income and expenses associated with the trust fund and the decommissioning liability incurred by Vistra Energy (and prior to the Effective Date, our Predecessor) are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates.

•

EFH Corp. files consolidated federal income tax and Texas state margin tax returns that included our results prior to the Effective Date; however, under a Federal and State Income Tax Allocation Agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., were recorded as if our Predecessor filed its own corporate income tax return. For the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, our Predecessor made income tax payments to EFH Corp. totaling $22 million and $29 million, respectively. In 2015, $609 million of income tax liability was eliminated under the terms of the Settlement Agreement. See Note 8 for discussion of cessation of payment of federal income taxes pursuant to the Settlement Agreement.

•

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, and in the future may sell or acquire, debt or debt securities issued by our Predecessor in open market transactions or through loan syndications.

•

As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debt securities totaling $382 million as of the Petition Date. These notes payable were classified as LSTC. The amounts of TCEH debt held by EFIH or EFH Corp. were eliminated as a result of the Settlement Agreement approved by the Bankruptcy Court in December 2015 (see Note 5). In conjunction with the Settlement Agreement approved by the Bankruptcy Court in December 2015, EFH Corp. and EFIH waived their rights to the claims associated with these debt securities resulting in a gain recorded in reorganization items (see Note 5). Interest expense on the notes totaled $1 million for the year ended December 31, 2015. Contractual interest, not paid or recorded, totaled $37 million for the year ended December 31, 2015. See Note 10.

Segment Information

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Information


.	SEGMENT INFORMATION

The operations of Vistra Energy are aligned into three reportable business segments: Wholesale Generation, Retail Electricity and Asset Closure. Our chief operating decision maker reviews the results of these three segments separately and allocates resources to the respective segments as part of our strategic operations. The Wholesale Generation and Retail Electricity businesses offer different products or services and involve different risks.

The Wholesale Generation segment is engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely in the ERCOT market. These activities are substantially all conducted by Luminant.

The Retail Electricity segment is engaged in retail sales of electricity and related services to residential, commercial and industrial customers, all largely in the ERCOT market. These activities are substantially all conducted by TXU Energy.

As discussed in Note 1, the Asset Closure segment was established effective January 1, 2018; however, these financial statements have been recast to reflect the changes resulting from the establishment of the Asset Closure segment. 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 recast information from prior periods to reflect this change in reportable segments. We have not allocated any unrealized gains or losses on hedging activities to the Asset Closure segment for the generation plants that were retired in January and February 2018.

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our Wholesale Generation and Retail Electricity segments.

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



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Operating revenues (a)
Wholesale Generation	$	1,794		$	212
Retail Electricity	4,058			912
Asset Closure	964			238
Eliminations	(1,386		)	(171		)
Consolidated operating revenues	$	5,430		$	1,191
Depreciation and amortization
Wholesale Generation	$	229		$	53
Retail Electricity	430			153
Asset Closure	1			—
Corporate and Other	40			11
Eliminations	(1		)	$	(1	)
Consolidated depreciation and amortization	$	699		$	216



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Operating income (loss)
Wholesale Generation	$	(118	)	$	(271	)
Retail Electricity	461			111
Asset Closure	(68		)	16
Corporate and Other	(77		)	(17		)
Consolidated operating income (loss)	$	198		$	(161	)
Interest expense and related charges
Wholesale Generation	$	21		$	(1	)
Corporate and Other	252			66
Eliminations	(80		)	(5		)
Consolidated interest expense and related charges	$	193		$	60
Income tax expense (benefit)(all Corporate and Other)	$	504		$	(70	)
Net income (loss)
Wholesale Generation	$	(114	)	$	(268	)
Retail Electricity	495			114
Asset Closure	(63		)	17
Corporate and Other	(572		)	(26		)
Consolidated net income (loss)	$	(254	)	$	(163	)
Capital expenditures
Wholesale Generation	$	150		$	77
Retail Electricity	—			5
Asset Closure	—			7
Corporate and Other	26			—
Consolidated capital expenditures	$	176		$	89

____________

(a)

For the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, includes third-party unrealized net gains (losses) from mark-to-market valuations of commodity positions of $(151) million and $(182) million, respectively, recorded to the Wholesale Generation segment and $18 million and $(6) million, respectively, recorded to the Retail Electricity segment. In addition, for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, unrealized net gains (losses) with affiliate of $(154) million and $(113) million, respectively, were recorded to operating revenues for the Wholesale Generation segment and corresponding unrealized net gains (losses) with affiliate of $154 million and $113 million, respectively, were recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results.



	December 31,
	2017		2016
Total assets
Wholesale Generation	$	6,834	$	6,673
Retail Electricity	6,156		5,753
Asset Closure	235		279
Corporate and Other and Eliminations	1,375		2,462
Consolidated total assets	$	14,600	$	15,167

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, 2017

Supplementary Financial Information [Abstract]

Supplementary Financial Information

SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions



	Successor				Predecessor
	Year Ended December 31, 2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Other income:
Office space sublease rental income (a)	$	11	$	2	$	—	$	—
Mineral rights royalty income (b)	3		1		3		4
Sale of land (b)	4		—		—		—
Curtailment gain on employee benefit plans (a)	—		4		—		—
Insurance settlement	—		—		9		—
Interest income	15		1		3		1
All other	4		2		4		13
Total other income	$	37	$	10	$	19	$	18
Other deductions:
Write-off of generation equipment (b)	2		—		45		—
Adjustment to asbestos liability	—		—		11		—
Impairment of favorable purchase contracts (Note 7)	—		—		—		8
Impairment of emission allowances (Note 7)	—		—		—		55
Impairment of mining development costs	—		—		—		19
All other	3		—		19		11
Total other deductions	$	5	$	—	$	75	$	93

____________


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


(b)	Reported in Wholesale Generation segment (Successor period only).

Restricted Cash



	December 31, 2017				December 31, 2016
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the Vistra Operations Credit Facilities (Note 12)	$	—	$	500	$	—	$	650
Amounts related to restructuring escrow accounts	59		—		90		—
Other	—		—		5		—
Total restricted cash	$	59	$	500	$	95	$	650

Trade Accounts Receivable



	December 31,
	2017			2016
Wholesale and retail trade accounts receivable	$	596		$	622
Allowance for uncollectible accounts	(14		)	(10		)
Trade accounts receivable — net	$	582		$	612

Gross trade accounts receivable at December 31, 2017 and 2016 included unbilled retail revenues of $251 million and $225 million, respectively.

Allowance for Uncollectible Accounts Receivable



	Successor					Predecessor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Allowance for uncollectible accounts receivable at beginning of period	$	10		$	—	$	9		$	15
Increase for bad debt expense	43			10		20			34
Decrease for account write-offs	(39		)	—		(16		)	(40		)
Allowance for uncollectible accounts receivable at end of period	$	14		$	10	$	13		$	9

Inventories by Major Category



	December 31,
	2017		2016
Materials and supplies	$	149	$	173
Fuel stock	83		88
Natural gas in storage	21		24
Total inventories	$	253	$	285

Other Investments



	December 31,
	2017		2016
Nuclear plant decommissioning trust	$	1,188	$	1,012
Land	49		49
Miscellaneous other	3		3
Total other investments	$	1,240	$	1,064

Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor's customers as a delivery fee surcharge over the life of the plant and deposited by Vistra Energy (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a receivable/payable (currently a receivable reported in noncurrent assets) that will ultimately be settled through changes in Oncor's delivery fees rates. The nuclear decommissioning trust fund was not a debtor in the Chapter 11 Cases. A summary of investments in the fund follows:



	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



	December 31, 2016
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	333	$	10	$	(3	)	$	340
Equity securities (c)	309		368		(5		)	672
Total	$	642	$	378	$	(8	)	$	1,012

____________


(a)	Includes realized gains and losses on securities sold.

(b)

The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's Investors Services, Inc. The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of 3.55% and 3.56% at December 31, 2017 and 2016, respectively, and an average maturity of 9 years at both December 31, 2017 and 2016.


(c)	The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.

Debt securities held at December 31, 2017 mature as follows: $111 million in one to 5 years, $99 million in five to 10 years and $220 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, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Realized gains	$	9		$	1		$	3		$	1
Realized losses	$	(11	)	$	—		$	(2	)	$	(1	)
Proceeds from sales of securities	$	252		$	25		$	201		$	401
Investments in securities	$	(272	)	$	(30	)	$	(215	)	$	(418	)

Property, Plant and Equipment



	December 31,
	2017			2016
Wholesale Generation:
Generation and mining	$	4,501		$	3,997
Retail Electricity	5			3
Corporate and Other	120			107
Total	4,626			4,107
Less accumulated depreciation	(282		)	(54		)
Net of accumulated depreciation	4,344			4,053
Nuclear fuel (net of accumulated amortization of $111 million and $31 million)	158			166
Construction work in progress:
Wholesale Generation	312			210
Retail Electricity	—			6
Corporate and Other	6			8
Total construction work in progress	318			224
Property, plant and equipment — net	$	4,820		$	4,443

Depreciation expense totaled $236 million, $54 million, $401 million and $767 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

Our property, plant and equipment consists of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements. At December 31, 2017, the capital lease for the building totaled $65 million with accumulated depreciation of $3 million. The estimated remaining useful lives range from 2 to 36 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 lignite/coal ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor. As part of fresh start reporting, new fair values were established for all AROs for the Successor.

At December 31, 2017, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.233 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 $45 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 year ended December 31, 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:



	Nuclear Plant Decommissioning		Mining Land Reclamation			Other			Total
Predecessor:
Liability at December 31, 2015	$	508	$	215		$	107		$	830
Additions:
Accretion — January 1, 2016 through October 2, 2016	22		16			5			43
Adjustment for new cost estimate	—		—			1			1
Incremental reclamation costs	—		14			12			26
Reductions:
Payments — January 1, 2016 through October 2, 2016	—		(37		)	(3		)	(40		)
Liability at October 2, 2016	530		208			122			860
Less amounts due currently	—		(50		)	(1		)	(51		)
Noncurrent liability at October 2, 2016	$	530	$	158		$	121		$	809
Successor:
Fair value of liability established at October 3, 2016	$	1,192	$	374		$	152		$	1,718
Additions:
Accretion — October 3, 2016 through December31, 2016	8		5			1			14
Reductions:
Payments — October 3, 2016 through December31, 2016	—		(4		)	(2		)	(6		)
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
Less amounts due currently	—		(93		)	(6		)	(99		)
Noncurrent liability at December 31, 2017	$	1,233	$	345		$	259		$	1,837

____________


(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,
	2017		2016
Unfavorable purchase and sales contracts	$	36	$	46
Other, including retirement and other employee benefits	220		174
Total other noncurrent liabilities and deferred credits	$	256	$	220

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $10 million, $3 million, $18 million and $23 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively. See Note 7 for intangible assets related to favorable purchase and sales contracts.

The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:



Year	Amount
2018	$	11
2019	$	9
2020	$	9
2021	$	1
2022	$	3

Fair Value of Debt



	December 31, 2017				December 31, 2016
Debt:	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities (Note 12)	$	4,323	$	4,334	$	4,515	$	4,552
Other long-term debt, excluding capital lease obligations (Note 12)	30		27		36		32
Mandatorily redeemable subsidiary preferred stock (Note 12)	70		70		70		70

We determine fair value in accordance with accounting standards as discussed in Note 15, and at December 31, 2017, our debt fair value represents Level 2 valuations. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.

Supplemental Cash Flow Information



	Successor						Predecessor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Cash payments related to:
Interest paid (a)	$	245		$	19		$	1,064		$	1,298
Capitalized interest	(7		)	(3		)	(9		)	(11		)
Interest paid (net of capitalized interest) (a)	$	238		$	16		$	1,055		$	1,287
Income taxes	$	63		$	(2	)	$	22		$	29
Reorganization items (b)	$	—		$	—		$	104		$	224
Noncash investing and financing activities:
Construction expenditures (c)	$	12		$	1		$	53		$	75

____________


(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.

The following table reconciles cash, cash equivalents and restricted cash reported in our statements of consolidated cash flows to the amounts reported in our consolidated balance sheets at December 31, 2017 and December 31, 2016:



	December 31, 2017		December 31, 2016
Cash and cash equivalents	$	1,487	$	843
Restricted cash included in current assets	59		95
Restricted cash included in noncurrent assets	500		650
Total cash, cash equivalents and restricted cash	$	2,046	$	1,588

Schedule I - Condensed Financial Information (Parent Company) (Notes)

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Financial Information of Parent Company Only Disclosure

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

VISTRA ENERGY CORP. (PARENT)

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF NET LOSS

(Millions of Dollars)



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Selling, general and administrative expense	$	(47	)	$	(7	)
Loss from operations	(47		)	(7		)
Interest income	4			—
Impacts of Tax Receivable Agreement	213			(22		)
Income (loss) before income taxes and equity earnings	170			(29		)
Pretax equity in gains (losses) of consolidated subsidiaries	80			(204		)
Income tax (expense) benefit	(504		)	70
Net loss	$	(254	)	$	(163	)

See Notes to the Condensed Financial Statements.

VISTRA ENERGY CORP. (PARENT)

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(Millions of Dollars)



	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Cash flows — operating activities:
Net loss	$	(254	)	$	(163	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Pretax equity in (gains) losses of consolidated subsidiaries	(80		)	204
Deferred income tax benefit (expense), net	418			(76		)
Impacts of Tax Receivables Agreement	(213		)	22
Other, net	23			3
Changes in operating assets and liabilities	(2		)	(26		)
Cash used in operating activities	(108		)	(36		)
Cash flows — financing activities:
Special dividend (Note 4)	—			(992		)
Other, net	(1		)	1
Cash used in financing activities	(1		)	(991		)
Cash flows — investing activities:
Dividend received from subsidiaries	1,506			997
Odessa Acquisition	(330		)	—
Cash provided by financing activities	1,176			997
Net change in cash, cash equivalents and restricted cash	1,067			(30		)
Cash, cash equivalents and restricted cash — beginning balance	116			146
Cash, cash equivalents and restricted cash — ending balance	$	1,183		$	116

See Notes to the Condensed Financial Statements.

VISTRA ENERGY CORP. (PARENT)

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(Millions of Dollars)



	December 31
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	1,124	$	26
Restricted cash	59		90
Other current assets	5		3
Total current assets	1,188		119
Equity investments in consolidated subsidiaries	4,927		6,067
Accumulated deferred income taxes	710		1,122
Other noncurrent assets	6		7
Total assets	$	6,831	$	7,315
LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable	$	11	$	—
Accrued taxes	59		31
Other current liabilities	86		91
Total current liabilities	156		122
Tax Receivable Agreement obligation	333		596
Total liabilities	489		718
Total shareholders' equity	6,342		6,597
Total liabilities and equity	$	6,831	$	7,315

See Notes to the Condensed Financial Statements.

NOTES TO CONDENSED FINANCIAL STATEMENTS


1.	BASIS OF PRESENTATION

The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of operations and cash flows of Vistra Energy Corp. (Parent). Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the financial statements and related notes of Vistra Energy Corp. and Subsidiaries included in the 2017 Annual Report on Form 10-K. Vistra Energy Corp.'s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.

Vistra Energy Corp. (Parent) will file a consolidated U.S. federal income tax return. All consolidated tax expenses/benefits and deferred tax assets/liabilities are recorded at Vistra Energy Corp. (Parent).

Adoption of New Accounting Standard — In November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash. The ASU requires restricted cash to be included in the cash and cash equivalents and a reconciliation between the change in cash and cash equivalents and the amounts presented on the balance sheet. The ASU modifies the presentation of our condensed statements of cash flows, but does not have a material impact on our condensed statements of net loss and condensed balance sheets. We adopted the standard on January 1, 2018. However, the adoption of this ASU has been reflected on a retrospective basis in the financial statements of the Successor. For the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, our condensed statements of cash flows previously reflected sources of cash of $32 million and $36 million, respectively, reported as changes in restricted cash that are now reported in net change in cash, cash equivalents and restricted cash.


2.	RESTRICTIONS ON SUBSIDIARIES

The agreement governing the Vistra Operations Credit Facilities (the Credit Facilities Agreement) generally restricts the ability of Vistra Operations Company LLC (Vistra Operations) to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2017, Vistra Operations can distribute approximately $1.0 billion to Vistra Energy Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent during the year ended December 31, 2017 of approximately $1.1 billion. Additionally, Vistra Operations may make distributions to Vistra Energy Corp. (Parent) in amounts sufficient for Vistra Energy Corp. (Parent) to make any payments required under the Tax Receivables Agreement or the Tax Matters Agreement or, to the extent arising out of Vistra Energy Corp.'s (Parent) ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2017, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled $3.9 billion.


3.	GUARANTEES

As of December 31, 2017, there are no material outstanding guarantees at Vistra Energy Corp. (Parent).


4.	DIVIDEND RESTRICTIONS

Under applicable law, Vistra Energy Corp. (Parent) is prohibited from paying any dividend to the extent that immediately following payment of such dividend there would be no statutory surplus or Vistra Energy Corp. (Parent) would be insolvent. On December 30, 2016, Vistra Energy Corp. (Parent) paid a special cash dividend in the aggregate amount of approximately $992 million to holders of record of its common stock on December 19, 2016.

Vistra Energy Corp. (Parent) received $1.506 billion and $997 million in dividends from its consolidated subsidiaries in the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively.


5.	SUPPLEMENTARY FINANCIAL INFORMATION

The following table reconciles cash, cash equivalents and restricted cash reported in our condensed statements of cash flows to the amounts reported in our condensed balance sheets at December 31, 2017 and December 31, 2016:



	December 31, 2017		December 31, 2016
Cash and cash equivalents	$	1,124	$	26
Restricted cash	59		90
Total cash, cash equivalents and restricted cash	$	1,183	$	116

Acquisition And Development Of Generation Facilities [Abstract]

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

+ References + Details

Business And Significant Accounting Policies (Policies)	12 Months Ended
Business And Significant Accounting Policies (Policies)	Dec. 31, 2017
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 GAAP and on the same basis as the audited financial statements and related notes contained in our prospectus filed in May 2017 with the SEC pursuant to Rule 424(b) of the Securities Act. 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, 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. 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 15 and 16 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, 2017 and 2016, 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 We record revenue from retail electricity sales under the accrual method of accounting. Revenues are recognized when electricity is provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue). We record wholesale generation revenue on an accrual basis for transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to ERCOT at the resource node, ERCOT ancillary service revenue for reliability services and certain other electricity sales. Revenue is recognized when electricity and other services are metered by ERCOT or delivered to our 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 $44 million, $9 million, $35 million and $44 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, 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. See Note 4 for discussion of impairments of certain long-lived assets recorded by the Predecessor. Finite-lived intangibles identified as a result of fresh start reporting 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, 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 (see Note 6). We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. As part of fresh start reporting, 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 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 and also offer pension benefits 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 multiemployer 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 Subsequent to the Effective Date, Vistra Energy will file a consolidated U.S. federal income tax return. 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. 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 8. We report interest and penalties related to uncertain tax positions as current income tax expense.
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 an asset has been impaired or 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 to be 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). 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 and applicable overhead, 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 10. 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, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. 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 income.
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.
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. 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. 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.

Acquisition and Development of Generation Facilities (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of recognized identified assets acquired and liabilities assumed

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

The following unaudited pro forma financial information for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015 assumes that the Lamar and Forney Acquisition occurred on January 1, 2015. 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, 2015, nor is the unaudited pro forma financial information indicative of future results of operations.



	Predecessor
	Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Revenues	$	4,116	$	6,133
Net income (loss)	$	22,835	$	(4,671	)

Disposition of Generation Facilities (Tables)

12 Months Ended

Dec. 31, 2017

Retirement of Generation Facilities [Abstract]

Retirements Of Generation Capacity [Table Text Block]

Luminant announced plans to retire three power plants with a total installed nameplate generation capacity of approximately 4,167 MW and two lignite mines. The plants were retired in January and February 2018. Luminant decided to retire these units given that they are projected to be uneconomic based on current market conditions and given the significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a Settlement Agreement discussed below. 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, 2017

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 and the year ended December 31, 2015, respectively, as reported in the statements of consolidated income (loss):



	Predecessor
	Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
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			141
Expenses related to other professional consulting and advisory services	39			69
Contract claims adjustments	13			54
Noncash adjustment for estimated allowed claims related to debt	—			896
Adjustment to affiliate claims pursuant to Settlement Agreement (Note 19)	—			(635		)
Gain on settlement of debt held by affiliates (Note 19)	—			(382		)
Gain on settlement of interest on debt held by affiliates	—			(20		)
Sponsor management agreement settlement	—			(19		)
Contract assumption adjustments	—			(14		)
Fees associated with extension/completion of the DIP Facility	—			9
Other	11			2
Total reorganization items	$	(22,121	)	$	101

Fresh-Start Reporting (Tables)

12 Months Ended

Dec. 31, 2017

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

Goodwill And Identifiable Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of identifiable intangible assets reported in the balance sheet

Identifiable intangible assets are comprised of the following:



	December 31, 2017						December 31, 2016
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	1,648	$	572	$	1,076	$	1,648	$	152	$	1,496
Software and other technology-related assets	183		47		136		147		9		138
Electricity supply contract (a)	—		—		—		190		2		188
Retail and wholesale contracts	154		87		67		164		38		126
Other identifiable intangible assets (b)	33		11		22		30		2		28
Total identifiable intangible assets subject to amortization	$	2,018	$	717	1,301		$	2,179	$	203	1,976
Retail trade names (not subject to amortization)					1,225						1,225
Mineral interests (not currently subject to amortization)					4						4
Total identifiable intangible assets					$	2,530					$	3,205

____________


(a)	Contract terminated in October 2017. See Note 4.


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

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

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



			Successor				Predecessor
Identifiable Intangible Asset	Statements of Consolidated Income (Loss) Line	Remaining useful lives at December 31, 2017 (weighted average in years)	Year Ended December 31, 2017		Period from October 3, 2016 through December 31, 2016		Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Retail customer relationship	Depreciation and amortization	4	$	420	$	152	$	9	$	17
Software and other technology-related assets	Depreciation and amortization	3	38		9		44		60
Electricity supply contract	Operating revenues	0	6		2		—		—
Retail and wholesale contracts	Operating revenues/fuel, purchased power costs and delivery fees	3	59		38		—		—
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	4	9		2		6		30
Total amortization expense (a)			$	532	$	203	$	59	$	107

____________


(a)	Amounts recorded in depreciation and amortization totaled $463 million, $162 million, $58 million and $85 million for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

Schedule of estimated amortization expense of identifiable intangible assets

As of December 31, 2017, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2018	$	367
2019	$	268
2020	$	191
2021	$	142
2022	$	4

As of December 31, 2017, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2018	$	367
2019	$	268
2020	$	191
2021	$	142
2022	$	4

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017		Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Current:
U.S. Federal	$	72	$	—		$	(6	)	$	(17	)
State	14		6			9			21
Total current	86		6			3			4
Deferred:
U.S. Federal	417		(75		)	(1,234		)	(811		)
State	1		(1		)	(36		)	(72		)
Total deferred	418		(76		)	(1,270		)	(883		)
Total	$	504	$	(70	)	$	(1,267	)	$	(879	)

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, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Income (loss) before income taxes	$	250		$	(233	)	$	21,584		$	(5,556	)
Income taxes at the U.S. federal statutory rate of 35%	88			(82		)	7,554			(1,945		)
Nondeductible TRA accretion	(80		)	5			—			—
Texas margin tax, net of federal benefit	13			3			(21		)	—
Impacts of tax reform legislation on deferred taxes	451			—			—			—
Effects of Tax Matters Agreement and tax-free spin-off transaction	19			—			—			—
Nondeductible debt restructuring costs	—			2			38			64
Nondeductible interest expense	—			—			12			21
Nontaxable gain on extinguishment of LSTC	—			—			(8,593		)	—
Valuation allowance	—			—			(210		)	210
Nondeductible goodwill impairment	—			—			—			770
Lignite depletion allowance	—			—			—			(8		)
Interest accrued for uncertain tax positions, net of tax	—			—			—			(2		)
Other	13			2			(47		)	11
Income tax expense (benefit)	$	504		$	(70	)	$	(1,267	)	$	(879	)
Effective tax rate	201.6		%	30.0		%	(5.9		)%	15.8		%

Schedule of deferred tax assets and liabilities

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2017 and 2016 are as follows:



	December 31,
	2017		2016
Noncurrent Deferred Income Tax Assets
Net operating loss (NOL) carryforwards	$	—	$	8
Property, plant and equipment	520		943
Intangible assets	81		29
Long-term debt	20		52
Employee benefit obligations	56		84
Commodity contracts and interest rate swaps	25		—
Other	8		6
Total deferred tax assets	$	710	$	1,122

Schedule of income tax contingencies

The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheets, during the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively:



	Predecessor
	Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Balance at beginning of period, excluding interest and penalties	$	36		$	65
Reductions based on tax positions related to prior years	(1		)	(11		)
Settlements with taxing authorities	(35		)	(18		)
Balance at end of period, excluding interest and penalties	$	—		$	36

Tax Receivable Agreement Obligation (Tables)

12 Months Ended

Dec. 31, 2017

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 year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016:



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

Interest Expense and Related Charges (Tables)

12 Months Ended

Dec. 31, 2017

Interest Expense and Related Charges [Abstract]

Schedule of Interest Expense and Related Charges



	Successor						Predecessor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Interest paid/accrued post-Emergence	$	213		$	51		$	—		$	—
Interest paid/accrued on debtor-in-possession financing	—			—			76			63
Adequate protection amounts paid/accrued	—			—			977			1,233
Unrealized mark-to-market net (gains) losses on interest rate swaps	(29		)	11			—			—
Capitalized interest	(7		)	(3		)	(9		)	(11		)
Other	16			1			5			4
Total interest expense and related charges	$	193		$	60		$	1,049		$	1,289

Contractual Interest Expense On Pre-Petition Liabilities]



	Predecessor
	Period from January 1, 2016 through October 2, 2016		Year Ended December 31, 2015
Contractual interest on debt classified as LSTC	$	1,570	$	2,070
Adequate protection amounts paid/accrued	930		1,173
Contractual interest on debt classified as LSTC not paid/accrued	$	640	$	897

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017							Period from October 3, 2016 through December 31, 2016
	Net Loss			Shares	Per Share Amount			Net Loss			Shares	Per Share Amount
Net loss available for common stock — basic	$	(254	)	427,761,460	$	(0.59	)	$	(163	)	427,560,620	$	(0.38	)
Net loss available for common stock — diluted	$	(254	)	427,761,460	$	(0.59	)	$	(163	)	427,560,620	$	(0.38	)

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017			December 31, 2016
Vistra Operations Credit Facilities (a)	$	4,323		$	4,515
Mandatorily redeemable subsidiary preferred stock (b)	70			70
8.82% Building Financing due semiannually through February 11, 2022 (c)	30			36
Capital lease obligations	—			2
Total long-term debt including amounts due currently	4,423			4,623
Less amounts due currently	(44		)	(46		)
Total long-term debt less amounts due currently	$	4,379		$	4,577

____________

(a)

At December 31, 2017, borrowings under the Vistra Operations Credit Facilities in our consolidated balance sheet include debt premiums of $21 million, debt discounts of $2 million and debt issuance costs of $7 million. At December 31, 2016, borrowings under the Vistra Operations Credit Facilities in our consolidated balance sheet include debt premiums of $25 million, debt discounts of $2 million and debt issuance costs of $8 million.


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


(c)	Obligation related to a corporate office space capital lease 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, 2017 are presented below.



		December 31, 2017
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity
Revolving Credit Facility (a)	August 4, 2021	$	860	$	—	$	834
Initial Term Loan B Facility (b)(c)	August 4, 2023	2,850		2,821		—
Incremental Term Loan B Facility (c)	December 14, 2023	1,000		990		—
Term Loan C Facility (d)	August 4, 2023	650		500		7
Total Vistra Operations Credit Facilities		$	5,360	$	4,311	$	841

___________


(a)	Facility to be used for general corporate purposes. Facility includes a $715 million letter of credit sub-facility, of which $26 million of letters of credit were outstanding at December 31, 2017.


(b)	Facility used to repay all amounts outstanding under our Predecessor's DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes.


(c)	Cash borrowings under the Term Loan B Facility reflect required scheduled quarterly payment in annual amount equal to 1% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed.

(d)

Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in our consolidated balance sheets. Cash borrowings reflect a $150 million principal reduction paid from restricted cash in December 2017. Amounts paid cannot be reborrowed. At December 31, 2017, the restricted cash supported $493 million in letters of credit outstanding (see Note 21), leaving $7 million in available letter of credit capacity.

Schedule of Maturities of Long-term Debt

Maturities — Long-term debt maturities at December 31, 2017 are as follows:



	December 31, 2017
2018	$	44
2019	44
2020	44
2021	45
2022	42
Thereafter	4,189
Unamortized premiums, discounts and debt issuance costs	15
Total long-term debt, including amounts due currently	$	4,423