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Vistra

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FY2018 Annual Report · Vistra
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2018 
Annual 
Report

Diversified, Integrated Operations

Vistra Energy is a premier, integrated power company, combining an innovative, customer-centric 

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Luminant, Vistra operates in 12 states. Our retail brands serve approximately 2.9 million residential, 

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natural gas, nuclear, coal, solar, and battery storage facilities.

2018 Retail Volumes

2018 Generating Capacity

2018 Energy Production (1)

Total 
~64 TWh

Total 
40,526 MW

Total 
~167 TWh

Residential 

Business 

34%

52%

Muni-Aggregation 

14%

Gas 

Coal 

Nuclear 

Solar 

61%

33%

6%

0.4%

Gas 

Coal 

Nuclear 

Solar 

51%

37%

12%

0.2%

(1) Excludes purchased power

   2018 Annual Report   |   1

We believe the combination of our industry-
leading retail business, in-the-money 
generation fleet, and advanced commercial 
operations is continuing to prove out 
its stable earnings profile and ability to 
generate significant free cash flow.

Curt Morgan

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Dear Fellow VST Stockholders,

2018 was a transformative year for Vistra Energy Corp. 

we have executed as of February 2019; the initiation of 

as we closed our merger with Dynegy in April, hosted

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capital allocation plan, and executed on various growth

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dividend in March of this year; and a commitment to achieve 

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and business development opportunities. We continued to 

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demonstrate the strength of the new integrated model—

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and wholesale operations with a focus on commercial

optimization and capital allocation, including returning capital 

to stockholders and prudent investment in the business. 

Vistra has also proven it can selectively and prudently deploy

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of the Odessa power plant, and the Upton 2 solar and 

battery projects. In addition, in 2019, we have announced an 

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commercial operations is continuing to prove out its stable 

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our retail presence to 19 states and the District of Columbia, 

accelerating our Midwest and Northeast growth strategy 

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while establishing a platform for future growth, including 

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in adjusted EBITDA from its ongoing operations in 2019 with 

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investment, at an estimated 4.0 times enterprise value to 

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ratio of approximately 66 percent. We are also committed 

EBITDA, is an example of our disciplined approach to growth 

opportunities, meeting our internal investment threshold while 

to returning capital to stockholders, as evidenced by the 

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capital allocation plan we announced in October 2018. 

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Our capital allocation plan includes authorization for up to 

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portfolio with Vistra’s existing retail and generation platform.

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Our success in 2018 and positive outlook for the year ahead

us to immediately integrate our businesses on Day 1

are a direct result of the relentless focus and dedication to 

and begin the synergy capture with minimal disruption. 

excellence Vistra achieved as “One Company, One Team” in

2018. I am pleased to discuss some of the highlights from the 

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per year of ongoing EBITDA synergies when we announced 

past year with you in the paragraphs that follow. 

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Dynegy Integration and Synergy Capture 

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We closed our merger with Dynegy in April 2018, creating

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with leading retail and generation operations in the key

competitive power markets in the United States. Importantly, 

we were able to complete the merger without any 

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plants. Vistra Energy now operates in 12 states, serving

approximately 240,000 commercial and industrial customers 

Similarly, at the time we announced the merger we

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enhancements, and we have since more than doubled 

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the potential for upside to this target as we continue to 

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execute in 2019. The success of this program is due to 

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also owns approximately 41 gigawatts of installed generation 

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fueled and more than 80 percent of which is located in the 

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The Dynegy integration and synergy capture has touched

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before and continued after the close of the merger allowed

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100 percent involvement from plant employees and a very 

detailed governance and tracking system to ensure capture. 

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possible, is also creating a consistent operating model and 

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   2018 Annual Report   |   3

An essential component of Vistra’s business 
is giving back to the communities where we 
live and work. Our employees volunteered 
over 5,000 hours through our employee-led 
volunteer program, Energy in Action.

Finally, we have also meaningfully increased our expectation

and expanded our retail footprint. It was a transformative

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transaction for our organization and set the stage for a 

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strong 2019.

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that was projected at the time of the merger announcement. 

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savings—some of which we have already achieved through 

balance sheet optimization activities executed in 2018, and 

the balance of which we expect to realize when we achieve 

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EBITDA. We were also able to put in place tax strategies that 

(cid:94)(cid:80)(cid:83)(cid:83)(cid:3)(cid:72)(cid:83)(cid:83)(cid:86)(cid:94)(cid:3)(cid:92)(cid:90)(cid:3)(cid:91)(cid:86)(cid:3)(cid:92)(cid:91)(cid:80)(cid:83)(cid:80)(cid:97)(cid:76)(cid:3)(cid:72)(cid:87)(cid:87)(cid:89)(cid:86)(cid:95)(cid:80)(cid:84)(cid:72)(cid:91)(cid:76)(cid:83)(cid:96)(cid:3)(cid:11)(cid:27)(cid:3)(cid:73)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:3)(cid:86)(cid:77)(cid:3)(cid:43)(cid:96)(cid:85)(cid:76)(cid:78)(cid:96)(cid:3)(cid:85)(cid:76)(cid:91)

(cid:86)(cid:87)(cid:76)(cid:89)(cid:72)(cid:91)(cid:80)(cid:85)(cid:78)(cid:3)(cid:83)(cid:86)(cid:90)(cid:90)(cid:76)(cid:90)(cid:19)(cid:3)(cid:89)(cid:76)(cid:90)(cid:92)(cid:83)(cid:91)(cid:80)(cid:85)(cid:78)(cid:3)(cid:80)(cid:85)(cid:3)(cid:72)(cid:87)(cid:87)(cid:89)(cid:86)(cid:95)(cid:80)(cid:84)(cid:72)(cid:91)(cid:76)(cid:83)(cid:96)(cid:3)(cid:11)(cid:32)(cid:23)(cid:23)(cid:3)(cid:84)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:3)(cid:80)(cid:85)

(cid:87)(cid:89)(cid:76)(cid:90)(cid:76)(cid:85)(cid:91)(cid:3)(cid:93)(cid:72)(cid:83)(cid:92)(cid:76)(cid:3)(cid:91)(cid:72)(cid:95)(cid:3)(cid:90)(cid:72)(cid:93)(cid:80)(cid:85)(cid:78)(cid:90)(cid:19)(cid:3)(cid:86)(cid:89)(cid:3)(cid:72)(cid:73)(cid:86)(cid:92)(cid:91)(cid:3)(cid:3)(cid:11)(cid:25)(cid:3)(cid:87)(cid:76)(cid:89)(cid:3)(cid:90)(cid:79)(cid:72)(cid:89)(cid:76)(cid:21)

After netting the purchase price, we estimate we created

(cid:85)(cid:76)(cid:72)(cid:89)(cid:83)(cid:96)(cid:3)(cid:11)(cid:30)(cid:3)(cid:73)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:3)(cid:80)(cid:85)(cid:3)(cid:93)(cid:72)(cid:83)(cid:92)(cid:76)(cid:3)(cid:77)(cid:86)(cid:89)(cid:3)(cid:86)(cid:92)(cid:89)(cid:3)(cid:90)(cid:91)(cid:86)(cid:74)(cid:82)(cid:79)(cid:86)(cid:83)(cid:75)(cid:76)(cid:89)(cid:90)(cid:3)(cid:77)(cid:89)(cid:86)(cid:84)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)

(cid:43)(cid:96)(cid:85)(cid:76)(cid:78)(cid:96)(cid:3)(cid:91)(cid:89)(cid:72)(cid:85)(cid:90)(cid:72)(cid:74)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:89)(cid:76)(cid:197)(cid:76)(cid:74)(cid:91)(cid:80)(cid:85)(cid:78)(cid:3)(cid:86)(cid:85)(cid:83)(cid:96)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:93)(cid:72)(cid:83)(cid:92)(cid:76)(cid:3)(cid:74)(cid:89)(cid:76)(cid:72)(cid:91)(cid:76)(cid:75)(cid:3)(cid:93)(cid:80)(cid:72)

(cid:44)(cid:41)(cid:48)(cid:59)(cid:43)(cid:40)(cid:19)(cid:3)(cid:77)(cid:89)(cid:76)(cid:76)(cid:3)(cid:74)(cid:72)(cid:90)(cid:79)(cid:3)(cid:197)(cid:86)(cid:94)(cid:19)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:91)(cid:72)(cid:95)(cid:3)(cid:90)(cid:96)(cid:85)(cid:76)(cid:89)(cid:78)(cid:80)(cid:76)(cid:90)(cid:183)(cid:72)(cid:83)(cid:83)(cid:86)(cid:74)(cid:72)(cid:91)(cid:80)(cid:85)(cid:78)(cid:3)(cid:85)(cid:86)(cid:3)
value to the underlying assets. We would not have been 

able to achieve this level of value creation in such a short 

period of time on a standalone basis. Moreover, the Dynegy 

(cid:91)(cid:89)(cid:72)(cid:85)(cid:90)(cid:72)(cid:74)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:84)(cid:86)(cid:93)(cid:76)(cid:75)(cid:3)(cid:92)(cid:90)(cid:3)(cid:80)(cid:85)(cid:91)(cid:86)(cid:3)(cid:85)(cid:76)(cid:94)(cid:3)(cid:84)(cid:72)(cid:89)(cid:82)(cid:76)(cid:91)(cid:90)(cid:19)(cid:3)(cid:90)(cid:79)(cid:80)(cid:77)(cid:91)(cid:76)(cid:75)(cid:3)(cid:92)(cid:90)(cid:3)(cid:91)(cid:86)(cid:3)(cid:72)(cid:3)(cid:78)(cid:72)(cid:90)(cid:20)

(cid:87)(cid:89)(cid:76)(cid:75)(cid:86)(cid:84)(cid:80)(cid:85)(cid:72)(cid:85)(cid:91)(cid:3)(cid:78)(cid:76)(cid:85)(cid:76)(cid:89)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:197)(cid:76)(cid:76)(cid:91)(cid:19)(cid:3)(cid:76)(cid:95)(cid:87)(cid:86)(cid:90)(cid:76)(cid:75)(cid:3)(cid:92)(cid:90)(cid:3)(cid:91)(cid:86)(cid:3)(cid:84)(cid:86)(cid:89)(cid:76)(cid:3)(cid:90)(cid:91)(cid:72)(cid:73)(cid:83)(cid:76)(cid:3)

(cid:74)(cid:72)(cid:87)(cid:72)(cid:74)(cid:80)(cid:91)(cid:96)(cid:3)(cid:87)(cid:72)(cid:96)(cid:84)(cid:76)(cid:85)(cid:91)(cid:90)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:76)(cid:85)(cid:76)(cid:89)(cid:78)(cid:96)(cid:3)(cid:84)(cid:72)(cid:89)(cid:82)(cid:76)(cid:91)(cid:90)(cid:3)(cid:80)(cid:85)(cid:3)(cid:55)(cid:49)(cid:52)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:48)(cid:58)(cid:54)(cid:20)(cid:53)(cid:44)(cid:19)

Strong Operations

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(cid:196)(cid:85)(cid:80)(cid:90)(cid:79)(cid:80)(cid:85)(cid:78)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:96)(cid:76)(cid:72)(cid:89)(cid:3)(cid:94)(cid:80)(cid:91)(cid:79)(cid:3)(cid:74)(cid:86)(cid:84)(cid:84)(cid:76)(cid:89)(cid:74)(cid:80)(cid:72)(cid:83)(cid:3)(cid:72)(cid:93)(cid:72)(cid:80)(cid:83)(cid:72)(cid:73)(cid:80)(cid:83)(cid:80)(cid:91)(cid:96)(cid:3)(cid:86)(cid:77)(cid:3)(cid:32)(cid:27)(cid:21)(cid:27)(cid:3)
percent compared to a target of 91 percent. Commercial

(cid:72)(cid:93)(cid:72)(cid:80)(cid:83)(cid:72)(cid:73)(cid:80)(cid:83)(cid:80)(cid:91)(cid:96)(cid:3)(cid:80)(cid:90)(cid:3)(cid:72)(cid:3)(cid:84)(cid:76)(cid:72)(cid:90)(cid:92)(cid:89)(cid:76)(cid:3)(cid:86)(cid:77)(cid:3)(cid:86)(cid:92)(cid:89)(cid:3)(cid:77)(cid:86)(cid:90)(cid:90)(cid:80)(cid:83)(cid:3)(cid:197)(cid:76)(cid:76)(cid:91)(cid:187)(cid:90)(cid:3)(cid:72)(cid:73)(cid:80)(cid:83)(cid:80)(cid:91)(cid:96)(cid:3)(cid:91)(cid:86)(cid:3)(cid:74)(cid:72)(cid:87)(cid:91)(cid:92)(cid:89)(cid:76)
gross margin from the market when the assets are in the

money, which is a core priority of our operations team and 

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(cid:84)(cid:80)(cid:75)(cid:20)(cid:32)(cid:23)(cid:90)(cid:3)(cid:72)(cid:89)(cid:76)(cid:3)(cid:80)(cid:84)(cid:87)(cid:89)(cid:76)(cid:90)(cid:90)(cid:80)(cid:93)(cid:76)(cid:3)(cid:77)(cid:86)(cid:89)(cid:3)(cid:72)(cid:85)(cid:96)(cid:3)(cid:78)(cid:76)(cid:85)(cid:76)(cid:89)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:197)(cid:76)(cid:76)(cid:91)(cid:19)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:94)(cid:76)(cid:3)(cid:94)(cid:80)(cid:83)(cid:83)
continue this focus on strong commercial availability in 2019.

(cid:44)(cid:88)(cid:92)(cid:72)(cid:83)(cid:83)(cid:96)(cid:3)(cid:80)(cid:84)(cid:87)(cid:86)(cid:89)(cid:91)(cid:72)(cid:85)(cid:91)(cid:19)(cid:3)(cid:86)(cid:92)(cid:89)(cid:3)(cid:78)(cid:76)(cid:85)(cid:76)(cid:89)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:91)(cid:76)(cid:72)(cid:84)(cid:3)(cid:90)(cid:72)(cid:94)(cid:3)(cid:72)(cid:3)(cid:75)(cid:76)(cid:74)(cid:89)(cid:76)(cid:72)(cid:90)(cid:76)(cid:3)(cid:80)(cid:85)(cid:3)
the number of employee injuries with only 44 recordable

incidents in 2018, with none being serious or life altering.

Vistra as a whole achieved a total recordable injury rate of 

(cid:23)(cid:21)(cid:31)(cid:25)(cid:19)(cid:3)(cid:94)(cid:79)(cid:80)(cid:74)(cid:79)(cid:3)(cid:87)(cid:83)(cid:72)(cid:74)(cid:76)(cid:75)(cid:3)(cid:92)(cid:90)(cid:3)(cid:80)(cid:85)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:91)(cid:86)(cid:87)(cid:3)(cid:88)(cid:92)(cid:72)(cid:89)(cid:91)(cid:80)(cid:83)(cid:76)(cid:3)(cid:94)(cid:79)(cid:76)(cid:85)(cid:3)(cid:74)(cid:86)(cid:84)(cid:87)(cid:72)(cid:89)(cid:76)(cid:75)
against industry peers. While we are pleased with the positive 

trend in improving our safety metrics, we will continue to

emphasize the importance of safety in our operations and

learn from all events and near misses that occur.

4 | 2018 Annual Report

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On the retail side, we advanced the ball and stayed in 

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front in our retail business with new initiatives such as

breakthrough advertising of our popular Free Nights and 

Solar Days product, the introduction of TXUeLease, an 

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our Formula Won customer experience initiative. We also

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Electric Company. The project at our Moss Landing site in

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2020 and is currently the world’s largest battery project. 

It will immediately place Vistra in a leadership position in

developed a comprehensive strategy to organically expand

the battery business and could propel us into future

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of these initiatives while organically growing residential

opportunities, as batteries and renewable assets continue 

to be an important component of our country’s 

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2008, expanding our large business markets platform, and 

energy future.

integrating the Dynegy retail business. Vistra’s retail team 

Financial Optimization

continues to excel in the areas of new product and business 

development, marketing and advertising, brand strategy and 

management, and customer interaction, as evidenced by

(cid:91)(cid:79)(cid:76)(cid:3)(cid:11)(cid:31)(cid:27)(cid:28)(cid:3)(cid:84)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)1 of adjusted EBITDA delivered by our retail 
segment in 2018—an increase of nearly 10 percent over our

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Growth and Development

In addition to executing on the Dynegy merger, in 2018 we

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term success. Without a strong balance sheet we would not 

be able to take advantage of growth opportunities like those 

I just outlined above. In 2018, we started a course that we 

believe will lead to the possibility of investment grade ratings 

for our debt—something unheard of in our industry in the 

recent past. We continue to target the lowest debt in the 

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even with the Crius transaction expecting to close in 2019. In 

changed the complexion of our company with the addition 

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Upton 2 solar facility began commercial operations in 

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interest savings per year. 

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Community and Sustainability

An essential component of Vistra’s business is giving back 

to the communities where we live and work. Our employees 

   2018 Annual Report   |   5

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volunteer program, Energy in Action. Vistra employees also

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TXU Energy AidSM campaign. We were honored to receive the

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supporting our diverse capital allocation plan emphasizing 

Spirit of Caring Award from the United Way of Metropolitan

disciplined growth, deleveraging, and returning capital to 

Dallas for our excellence in supporting the United Way's 

stockholders. 

annual campaign and outstanding community involvement 

throughout the year.

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Vistra understands that our operations have an environmental 

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impact, but we also can’t lose sight of the fact that electricity 

is essential to society’s most important priorities, and reliable 

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service we provide. We are constantly balancing innovation, 

reliability, and sustainability in our operations. In 2018, we

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(cid:91)(cid:79)(cid:76)(cid:3)(cid:58)(cid:13)(cid:55)(cid:3)(cid:28)(cid:23)(cid:23)(cid:3)(cid:73)(cid:96)(cid:3)(cid:84)(cid:86)(cid:89)(cid:76)(cid:3)(cid:91)(cid:79)(cid:72)(cid:85)(cid:3)(cid:31)(cid:23)(cid:3)(cid:87)(cid:76)(cid:89)(cid:74)(cid:76)(cid:85)(cid:91)2 since we emerged 
from bankruptcy in October 2016. We believe our valuation

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markets grow more comfortable with the earnings stability

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our commitments to the environment, our community 

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company model, and as we fully rotate our stockholder base. 

involvement, and our corporate governance. On our website

We are referring to 2019 as a “Year of Execution” where we

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targets, so please stay tuned for that announcement.

In Closing

Vistra ended 2018 delivering adjusted EBITDA from ongoing 

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on cost management. Vistra also delivered adjusted free

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conversion ratio is a highly attractive feature of our company,

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returning capital to stockholders, and meeting or exceeding

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stockholders and I look forward to continuing our dialogue.

Sincerely,

Curt Morgan
Curt Morgan

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1  Non-GAAP Financial Measures and Forward Looking Statements 

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assumptions. For a discussion identifying important factors that could cause actual results to vary materially from those anticipated in the 

(cid:77)(cid:86)(cid:89)(cid:94)(cid:72)(cid:89)(cid:75)(cid:20)(cid:83)(cid:86)(cid:86)(cid:82)(cid:80)(cid:85)(cid:78)(cid:3)(cid:90)(cid:91)(cid:72)(cid:91)(cid:76)(cid:84)(cid:76)(cid:85)(cid:91)(cid:90)(cid:19)(cid:3)(cid:90)(cid:76)(cid:76)(cid:3)(cid:61)(cid:80)(cid:90)(cid:91)(cid:89)(cid:72)(cid:3)(cid:44)(cid:85)(cid:76)(cid:89)(cid:78)(cid:96)(cid:187)(cid:90)(cid:3)(cid:196)(cid:83)(cid:80)(cid:85)(cid:78)(cid:90)(cid:3)(cid:94)(cid:80)(cid:91)(cid:79)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:58)(cid:44)(cid:42)(cid:3)(cid:80)(cid:85)(cid:74)(cid:83)(cid:92)(cid:75)(cid:80)(cid:85)(cid:78)(cid:19)(cid:3)(cid:73)(cid:92)(cid:91)(cid:3)(cid:85)(cid:86)(cid:91)(cid:3)(cid:83)(cid:80)(cid:84)(cid:80)(cid:91)(cid:76)(cid:75)(cid:3)(cid:91)(cid:86)(cid:19)(cid:3)(cid:184)(cid:52)(cid:72)(cid:85)(cid:72)(cid:78)(cid:76)(cid:84)(cid:76)(cid:85)(cid:91)(cid:187)(cid:90)(cid:3)(cid:43)(cid:80)(cid:90)(cid:74)(cid:92)(cid:90)(cid:90)(cid:80)(cid:86)(cid:85)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:40)(cid:85)(cid:72)(cid:83)(cid:96)(cid:90)(cid:80)(cid:90)(cid:3)

(cid:86)(cid:77)(cid:3)(cid:45)(cid:80)(cid:85)(cid:72)(cid:85)(cid:74)(cid:80)(cid:72)(cid:83)(cid:3)(cid:42)(cid:86)(cid:85)(cid:75)(cid:80)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:57)(cid:76)(cid:90)(cid:92)(cid:83)(cid:91)(cid:90)(cid:3)(cid:86)(cid:77)(cid:3)(cid:54)(cid:87)(cid:76)(cid:89)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:90)(cid:185)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:184)(cid:57)(cid:80)(cid:90)(cid:82)(cid:3)(cid:45)(cid:72)(cid:74)(cid:91)(cid:86)(cid:89)(cid:90)(cid:185)(cid:3)(cid:80)(cid:85)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:45)(cid:86)(cid:89)(cid:84)(cid:3)(cid:24)(cid:23)(cid:20)(cid:50)(cid:3)(cid:87)(cid:86)(cid:89)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:86)(cid:77)(cid:3)(cid:91)(cid:79)(cid:80)(cid:90)(cid:3)(cid:40)(cid:85)(cid:85)(cid:92)(cid:72)(cid:83)(cid:3)(cid:57)(cid:76)(cid:87)(cid:86)(cid:89)(cid:91)(cid:21)

2(cid:3)(cid:3)(cid:57)(cid:76)(cid:197)(cid:76)(cid:74)(cid:91)(cid:90)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:80)(cid:85)(cid:74)(cid:89)(cid:76)(cid:72)(cid:90)(cid:76)(cid:3)(cid:80)(cid:85)(cid:3)(cid:61)(cid:80)(cid:90)(cid:91)(cid:89)(cid:72)(cid:187)(cid:90)(cid:3)(cid:90)(cid:79)(cid:72)(cid:89)(cid:76)(cid:3)(cid:87)(cid:89)(cid:80)(cid:74)(cid:76)(cid:3)(cid:77)(cid:89)(cid:86)(cid:84)(cid:3)(cid:43)(cid:76)(cid:74)(cid:76)(cid:84)(cid:73)(cid:76)(cid:89)(cid:3)(cid:26)(cid:24)(cid:19)(cid:3)(cid:25)(cid:23)(cid:24)(cid:31)(cid:3)(cid:72)(cid:90)(cid:3)(cid:74)(cid:86)(cid:84)(cid:87)(cid:72)(cid:89)(cid:76)(cid:75)(cid:3)(cid:91)(cid:86)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:87)(cid:89)(cid:80)(cid:74)(cid:76)(cid:3)(cid:94)(cid:79)(cid:76)(cid:89)(cid:76)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:59)(cid:76)(cid:95)(cid:72)(cid:90)(cid:3)(cid:42)(cid:86)(cid:84)(cid:87)(cid:76)(cid:91)(cid:80)(cid:91)(cid:80)(cid:93)(cid:76)(cid:3)(cid:44)(cid:83)(cid:76)(cid:74)(cid:91)(cid:89)(cid:80)(cid:74)(cid:3)
(cid:47)(cid:86)(cid:83)(cid:75)(cid:80)(cid:85)(cid:78)(cid:90)(cid:3)(cid:73)(cid:86)(cid:85)(cid:75)(cid:90)(cid:3)(cid:94)(cid:76)(cid:89)(cid:76)(cid:3)(cid:91)(cid:89)(cid:72)(cid:75)(cid:80)(cid:85)(cid:78)(cid:3)(cid:86)(cid:85)(cid:3)(cid:58)(cid:76)(cid:87)(cid:91)(cid:76)(cid:84)(cid:73)(cid:76)(cid:89)(cid:3)(cid:26)(cid:23)(cid:19)(cid:3)(cid:25)(cid:23)(cid:24)(cid:29)(cid:3)(cid:15)(cid:80)(cid:84)(cid:84)(cid:76)(cid:75)(cid:80)(cid:72)(cid:91)(cid:76)(cid:83)(cid:96)(cid:3)(cid:87)(cid:89)(cid:80)(cid:86)(cid:89)(cid:3)(cid:91)(cid:86)(cid:3)(cid:76)(cid:84)(cid:76)(cid:89)(cid:78)(cid:76)(cid:85)(cid:74)(cid:76)(cid:3)(cid:77)(cid:89)(cid:86)(cid:84)(cid:3)(cid:73)(cid:72)(cid:85)(cid:82)(cid:89)(cid:92)(cid:87)(cid:91)(cid:74)(cid:96)(cid:16)(cid:19)(cid:3)(cid:72)(cid:90)(cid:3)(cid:72)(cid:75)(cid:81)(cid:92)(cid:90)(cid:91)(cid:76)(cid:75)(cid:3)(cid:77)(cid:86)(cid:89)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:90)(cid:87)(cid:76)(cid:74)(cid:80)(cid:72)(cid:83)(cid:3)

(cid:75)(cid:80)(cid:93)(cid:80)(cid:75)(cid:76)(cid:85)(cid:75)(cid:3)(cid:86)(cid:77)(cid:3)(cid:11)(cid:25)(cid:21)(cid:26)(cid:25)(cid:22)(cid:90)(cid:79)(cid:72)(cid:89)(cid:76)(cid:3)(cid:87)(cid:72)(cid:80)(cid:75)(cid:3)(cid:80)(cid:85)(cid:3)(cid:43)(cid:76)(cid:74)(cid:76)(cid:84)(cid:73)(cid:76)(cid:89)(cid:3)(cid:25)(cid:23)(cid:24)(cid:29)(cid:21)

6   |   2018 Annual Report

Non-GAAP Reconciliations  — Adjusted EBITDA
(cid:64)(cid:76)(cid:72)(cid:89)(cid:3)(cid:44)(cid:85)(cid:75)(cid:76)(cid:75)(cid:3)(cid:43)(cid:76)(cid:74)(cid:76)(cid:84)(cid:73)(cid:76)(cid:89)(cid:3)(cid:26)(cid:24)(cid:19)(cid:3)(cid:25)(cid:23)(cid:24)(cid:31)(cid:3)(cid:3)(cid:15)(cid:60)(cid:85)(cid:72)(cid:92)(cid:75)(cid:80)(cid:91)(cid:76)(cid:75)(cid:16)(cid:3)(cid:15)(cid:52)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:90)(cid:3)(cid:86)(cid:77)(cid:3)(cid:43)(cid:86)(cid:83)(cid:83)(cid:72)(cid:89)(cid:90)(cid:16)

Net Income (Loss)

(cid:48)(cid:85)(cid:74)(cid:86)(cid:84)(cid:76)(cid:3)(cid:91)(cid:72)(cid:95)(cid:3)(cid:76)(cid:95)(cid:87)(cid:76)(cid:85)(cid:90)(cid:76)(cid:3)(cid:15)(cid:73)(cid:76)(cid:85)(cid:76)(cid:196)(cid:91)(cid:16)
Interest expense and related charges
Depreciation and amortization (cid:15)(cid:72)(cid:16)

EBITDA

(cid:3) (cid:11)(cid:3)

(cid:3) (cid:3)
(cid:3) (cid:3)

(cid:3) (cid:11)(cid:3)

(cid:60)(cid:85)(cid:89)(cid:76)(cid:72)(cid:83)(cid:80)(cid:97)(cid:76)(cid:75)(cid:3)(cid:85)(cid:76)(cid:91)(cid:3)(cid:15)(cid:78)(cid:72)(cid:80)(cid:85)(cid:16)(cid:3)(cid:86)(cid:89)(cid:3)(cid:83)(cid:86)(cid:90)(cid:90)(cid:3)(cid:89)(cid:76)(cid:90)(cid:92)(cid:83)(cid:91)(cid:80)(cid:85)(cid:78)(cid:3)
from hedging transactions
(cid:45)(cid:89)(cid:76)(cid:90)(cid:79)(cid:3)(cid:90)(cid:91)(cid:72)(cid:89)(cid:91)(cid:3)(cid:22)(cid:3)(cid:87)(cid:92)(cid:89)(cid:74)(cid:79)(cid:72)(cid:90)(cid:76)(cid:3)(cid:72)(cid:74)(cid:74)(cid:86)(cid:92)(cid:85)(cid:91)(cid:80)(cid:85)(cid:78)(cid:3)(cid:80)(cid:84)(cid:87)(cid:72)(cid:74)(cid:91)(cid:90)    
Impacts of tax receivable agreement

(cid:3) (cid:3)

(cid:53)(cid:86)(cid:85)(cid:20)(cid:74)(cid:72)(cid:90)(cid:79)(cid:3)(cid:74)(cid:86)(cid:84)(cid:87)(cid:76)(cid:85)(cid:90)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:76)(cid:95)(cid:87)(cid:76)(cid:85)(cid:90)(cid:76)(cid:90)
Transition and merger expenses
Other, net

Adjusted EBITDA, including 
Odessa earnout buybacks
Impact of Odessa earnout buybacks

Adjusted EBITDA

(cid:3) (cid:3)

(cid:3) (cid:11)(cid:3)

(cid:3) (cid:11)(cid:3)

Retail

Wholesale

Eliminations /  
Corp and 
Other

Ongoing 
Operations 
Consolidated

Asset Closure

Vistra Energy 
Consolidated

(cid:30)(cid:24)(cid:25) (cid:3) (cid:11)(cid:3)
—    

(cid:30) (cid:3) (cid:3)
(cid:26)(cid:24)(cid:31)    
(cid:24)(cid:19)(cid:23)(cid:26)(cid:30) (cid:3) (cid:11)(cid:3)

(cid:24)(cid:28)(cid:32) (cid:3) (cid:11)(cid:3)
— (cid:3) (cid:3)
(cid:25)(cid:26) (cid:3) (cid:3)
1,068    

(cid:24)(cid:19)(cid:25)(cid:28)(cid:23) (cid:3) (cid:11)(cid:3)

(cid:15)(cid:25)(cid:23)(cid:29)(cid:16) (cid:3) (cid:3)

(cid:28)(cid:30)(cid:24) (cid:3) (cid:3)

26    
—    
—    
1 (cid:3) (cid:3)
(cid:15)(cid:24)(cid:26)(cid:16) (cid:3) (cid:3)

14    
— (cid:3) (cid:3)
— (cid:3) (cid:3)
(cid:26)(cid:27)    
(cid:26)(cid:25) (cid:3) (cid:3)

(cid:15)(cid:31)(cid:30)(cid:31)(cid:16) (cid:3) (cid:11)(cid:3)

(cid:15)(cid:27)(cid:28)(cid:16) (cid:3) (cid:3)
(cid:28)(cid:27)(cid:25) (cid:3) (cid:3)
86 (cid:3) (cid:3)
(cid:15)(cid:25)(cid:32)(cid:28)(cid:16) (cid:3) (cid:11)(cid:3)

(cid:24)(cid:28) (cid:3) (cid:3)

—    

(cid:30)(cid:32) (cid:3) (cid:3)
(cid:30)(cid:26) (cid:3) (cid:3)
196 (cid:3) (cid:3)
(cid:15)(cid:25)(cid:26)(cid:16) (cid:3) (cid:3)

(cid:15)(cid:30)(cid:16) (cid:3) (cid:11)(cid:3)

(cid:15)(cid:27)(cid:28)(cid:16)    
(cid:28)(cid:30)(cid:25)    
(cid:24)(cid:19)(cid:27)(cid:30)(cid:25)    
(cid:24)(cid:19)(cid:32)(cid:32)(cid:25) (cid:3) (cid:11)(cid:3)

(cid:26)(cid:31)(cid:23)    

40    
(cid:30)(cid:32)    
(cid:30)(cid:26)    
(cid:25)(cid:26)(cid:24)    
(cid:15)(cid:27)(cid:16) (cid:3) (cid:3)

(cid:15)(cid:27)(cid:32)(cid:16) (cid:3) (cid:11)(cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
(cid:15)(cid:27)(cid:32)(cid:16) (cid:3) (cid:11)(cid:3)

— (cid:3) (cid:3)

1    
— (cid:3) (cid:3)
— (cid:3) (cid:3)
2 (cid:3) (cid:3)
(cid:15)(cid:26)(cid:16) (cid:3) (cid:3)

(cid:31)(cid:27)(cid:28) (cid:3) (cid:11)(cid:3)

(cid:24)(cid:19)(cid:32)(cid:23)(cid:24) (cid:3) (cid:11)(cid:3)

(cid:27)(cid:28) (cid:3) (cid:11)(cid:3)

(cid:25)(cid:19)(cid:30)(cid:32)(cid:24) (cid:3) (cid:11)(cid:3)

(cid:15)(cid:27)(cid:32)(cid:16) (cid:3) (cid:11)(cid:3)

18

18

(cid:31)(cid:27)(cid:28) (cid:3) (cid:11)(cid:3)

(cid:24)(cid:19)(cid:32)(cid:24)(cid:32) (cid:3) (cid:11)(cid:3)

(cid:27)(cid:28) (cid:3) (cid:11)(cid:3)

(cid:25)(cid:19)(cid:31)(cid:23)(cid:32) (cid:3) (cid:11)(cid:3)

(cid:15)(cid:27)(cid:32)(cid:16) (cid:3) (cid:11)(cid:3)

(cid:15)(cid:28)(cid:29)(cid:16)

(cid:15)(cid:27)(cid:28)(cid:16)
(cid:28)(cid:30)(cid:25)
(cid:24)(cid:19)(cid:27)(cid:30)(cid:25)

(cid:24)(cid:19)(cid:32)(cid:27)(cid:26)

(cid:26)(cid:31)(cid:23)

41

(cid:30)(cid:32)
(cid:30)(cid:26)
(cid:25)(cid:26)(cid:26)
(cid:15)(cid:30)(cid:16)

(cid:25)(cid:19)(cid:30)(cid:27)(cid:25)

18

(cid:25)(cid:19)(cid:30)(cid:29)(cid:23)

(cid:15)(cid:72)(cid:16)(cid:3)(cid:48)(cid:85)(cid:74)(cid:83)(cid:92)(cid:75)(cid:76)(cid:90)(cid:3)(cid:85)(cid:92)(cid:74)(cid:83)(cid:76)(cid:72)(cid:89)(cid:3)(cid:77)(cid:92)(cid:76)(cid:83)(cid:3)(cid:72)(cid:84)(cid:86)(cid:89)(cid:91)(cid:80)(cid:97)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:86)(cid:77)(cid:3)(cid:11)(cid:30)(cid:31)(cid:3)(cid:84)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:3)(cid:80)(cid:85)(cid:3)(cid:44)(cid:57)(cid:42)(cid:54)(cid:59)(cid:21)

Non-GAAP Reconciliations  — Adjusted Free Cash Flow
(cid:64)(cid:76)(cid:72)(cid:89)(cid:3)(cid:44)(cid:85)(cid:75)(cid:76)(cid:75)(cid:3)(cid:43)(cid:76)(cid:74)(cid:76)(cid:84)(cid:73)(cid:76)(cid:89)(cid:3)(cid:26)(cid:24)(cid:19)(cid:3)(cid:25)(cid:23)(cid:24)(cid:31)(cid:3)(cid:3)(cid:15)(cid:60)(cid:85)(cid:72)(cid:92)(cid:75)(cid:80)(cid:91)(cid:76)(cid:75)(cid:16)(cid:3)(cid:15)(cid:52)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:90)(cid:3)(cid:86)(cid:77)(cid:3)(cid:43)(cid:86)(cid:83)(cid:83)(cid:72)(cid:89)(cid:90)(cid:16)

Adjusted EBITDA
Interest paid, net (cid:15)(cid:72)(cid:16)
Taxes paid (cid:15)(cid:73)(cid:16)
Severance
Working capital, margin deposits and derivative related cash activities

(cid:57)(cid:76)(cid:74)(cid:83)(cid:72)(cid:84)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:89)(cid:76)(cid:84)(cid:76)(cid:75)(cid:80)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)
Taxes related to Alcoa settlement
Transition and merger expense
Transition related Capex
Impact of Odessa earnout buybacks on EBITDA
Changes in other operating assets and liabilities

Cash provided by operating activities
Capital expenditures including LTSA prepayments and nuclear fuel purchases (cid:15)(cid:74)(cid:16)
Development and growth expenditures
Other net investing activities (cid:15)(cid:75)(cid:16)

Free cash flow
Working capital, margin deposits and derivative related cash activities
Development and growth expenditures
Severance
Taxes related to Alcoa settlement
Transition and merger expense
Transition related Capex
Other

Adjusted free cash flow

(cid:48)(cid:84)(cid:87)(cid:72)(cid:74)(cid:91)(cid:3)(cid:86)(cid:77)(cid:3)(cid:54)(cid:75)(cid:76)(cid:90)(cid:90)(cid:72)(cid:3)(cid:76)(cid:72)(cid:89)(cid:85)(cid:86)(cid:92)(cid:91)(cid:3)(cid:73)(cid:92)(cid:96)(cid:73)(cid:72)(cid:74)(cid:82)(cid:90)(cid:3)(cid:86)(cid:85)(cid:3)(cid:77)(cid:89)(cid:76)(cid:76)(cid:3)(cid:74)(cid:72)(cid:90)(cid:79)(cid:3)(cid:197)(cid:86)(cid:94)
Adjusted free cash flow before growth

Ongoing 
Operations

Asset Closure

Vistra Energy 
Consolidated

(cid:3) (cid:11)(cid:3)

(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)

(cid:3) (cid:11)(cid:3)

(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)

(cid:3) (cid:11)(cid:3)

(cid:3) (cid:3)
(cid:3) (cid:3)

(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)

(cid:3) (cid:11)(cid:3)

  (cid:11)(cid:3)

(cid:25)(cid:19)(cid:31)(cid:23)(cid:32) (cid:3) (cid:11)(cid:3)
(cid:15)(cid:29)(cid:26)(cid:29)(cid:16)    
(cid:15)(cid:29)(cid:24)(cid:16) (cid:3) (cid:3)
(cid:15)(cid:25)(cid:16) (cid:3) (cid:3)
(cid:15)(cid:25)(cid:28)(cid:32)(cid:16)    
(cid:15)(cid:27)(cid:24)(cid:16) (cid:3) (cid:3)
(cid:15)(cid:27)(cid:28)(cid:16)    
(cid:15)(cid:24)(cid:30)(cid:24)(cid:16)    
(cid:15)(cid:25)(cid:26)(cid:16)    
(cid:15)(cid:24)(cid:31)(cid:16)    
64 (cid:3) (cid:3)
(cid:24)(cid:19)(cid:29)(cid:24)(cid:30) (cid:3) (cid:11)(cid:3)
(cid:15)(cid:28)(cid:24)(cid:23)(cid:16)    
(cid:15)(cid:26)(cid:27)(cid:16)    
(cid:15)(cid:24)(cid:29)(cid:16)    
(cid:24)(cid:19)(cid:23)(cid:28)(cid:30) (cid:3) (cid:11)(cid:3)
(cid:25)(cid:28)(cid:32)    
(cid:26)(cid:27)    
2    
(cid:27)(cid:28)    
(cid:24)(cid:30)(cid:24)    
(cid:25)(cid:26)    
(cid:15)(cid:25)(cid:16)    

(cid:24)(cid:19)(cid:28)(cid:31)(cid:32) (cid:3) (cid:11)(cid:3)
22    

(cid:15)(cid:27)(cid:32)(cid:16) (cid:3) (cid:11)(cid:3)
— (cid:3) (cid:3)
(cid:15)(cid:24)(cid:27)(cid:16) (cid:3) (cid:3)
(cid:15)(cid:25)(cid:23)(cid:16) (cid:3) (cid:3)
— (cid:3) (cid:3)
(cid:15)(cid:28)(cid:32)(cid:16) (cid:3) (cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
(cid:15)(cid:27)(cid:16) (cid:3) (cid:3)

(cid:15)(cid:24)(cid:27)(cid:29)(cid:16) (cid:3) (cid:11)(cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
(cid:15)(cid:24)(cid:27)(cid:29)(cid:16) (cid:3) (cid:11)(cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
20    
— (cid:3) (cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
— (cid:3) (cid:3)
(cid:15)(cid:24)(cid:25)(cid:29)(cid:16) (cid:3) (cid:11)(cid:3)
—    

(cid:24)(cid:19)(cid:29)(cid:24)(cid:24)   (cid:11)(cid:3)

(cid:15)(cid:24)(cid:25)(cid:29)(cid:16)   (cid:11)(cid:3)

(cid:25)(cid:19)(cid:30)(cid:29)(cid:23)

(cid:15)(cid:29)(cid:26)(cid:29)(cid:16)
(cid:15)(cid:30)(cid:28)(cid:16)
(cid:15)(cid:25)(cid:25)(cid:16)
(cid:15)(cid:25)(cid:28)(cid:32)(cid:16)
(cid:15)(cid:24)(cid:23)(cid:23)(cid:16)
(cid:15)(cid:27)(cid:28)(cid:16)
(cid:15)(cid:24)(cid:30)(cid:24)(cid:16)
(cid:15)(cid:25)(cid:26)(cid:16)
(cid:15)(cid:24)(cid:31)(cid:16)
(cid:15)(cid:29)(cid:23)(cid:16)

(cid:24)(cid:19)(cid:27)(cid:30)(cid:24)

(cid:15)(cid:28)(cid:24)(cid:23)(cid:16)
(cid:15)(cid:26)(cid:27)(cid:16)
(cid:15)(cid:24)(cid:29)(cid:16)

(cid:32)(cid:24)(cid:24)

(cid:25)(cid:28)(cid:32)
(cid:26)(cid:27)
2

(cid:27)(cid:28)
(cid:24)(cid:30)(cid:24)
(cid:25)(cid:26)
(cid:15)(cid:25)(cid:16)

(cid:24)(cid:19)(cid:27)(cid:29)(cid:26)
22

(cid:24)(cid:19)(cid:27)(cid:31)(cid:28)

(cid:15)(cid:72)(cid:16)(cid:3)(cid:3)(cid:53)(cid:76)(cid:91)(cid:3)(cid:86)(cid:77)(cid:3)(cid:80)(cid:85)(cid:91)(cid:76)(cid:89)(cid:76)(cid:90)(cid:91)(cid:3)(cid:89)(cid:76)(cid:74)(cid:76)(cid:80)(cid:93)(cid:76)(cid:75)(cid:21)(cid:3)(cid:44)(cid:95)(cid:74)(cid:83)(cid:92)(cid:75)(cid:76)(cid:90)(cid:3)(cid:77)(cid:76)(cid:76)(cid:90)(cid:3)(cid:87)(cid:72)(cid:80)(cid:75)(cid:3)(cid:86)(cid:85)(cid:3)(cid:61)(cid:80)(cid:90)(cid:91)(cid:89)(cid:72)(cid:3)(cid:54)(cid:87)(cid:76)(cid:89)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:90)(cid:3)(cid:42)(cid:89)(cid:76)(cid:75)(cid:80)(cid:91)(cid:3)(cid:45)(cid:72)(cid:74)(cid:80)(cid:83)(cid:80)(cid:91)(cid:96)(cid:3)(cid:89)(cid:76)(cid:87)(cid:89)(cid:80)(cid:74)(cid:80)(cid:85)(cid:78)(cid:3)(cid:80)(cid:85)(cid:3)(cid:45)(cid:76)(cid:73)(cid:89)(cid:92)(cid:72)(cid:89)(cid:96)(cid:3)(cid:25)(cid:23)(cid:24)(cid:31)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:89)(cid:76)(cid:196)(cid:85)(cid:72)(cid:85)(cid:74)(cid:80)(cid:85)(cid:78)(cid:3)(cid:80)(cid:85)(cid:3)(cid:49)(cid:92)(cid:85)(cid:76)(cid:3)(cid:25)(cid:23)(cid:24)(cid:31)(cid:19)(cid:3)(cid:40)(cid:92)(cid:78)(cid:92)(cid:90)(cid:91)(cid:3)(cid:25)(cid:23)(cid:24)(cid:31)(cid:19)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)

December 2018.

(cid:15)(cid:73)(cid:16)(cid:3)(cid:44)(cid:95)(cid:74)(cid:83)(cid:92)(cid:75)(cid:76)(cid:90)(cid:3)(cid:91)(cid:72)(cid:95)(cid:76)(cid:90)(cid:3)(cid:87)(cid:72)(cid:80)(cid:75)(cid:3)(cid:89)(cid:76)(cid:83)(cid:72)(cid:91)(cid:76)(cid:75)(cid:3)(cid:91)(cid:86)(cid:3)(cid:40)(cid:83)(cid:74)(cid:86)(cid:72)(cid:3)(cid:90)(cid:76)(cid:91)(cid:91)(cid:83)(cid:76)(cid:84)(cid:76)(cid:85)(cid:91)(cid:21)
(cid:15)(cid:74)(cid:16)(cid:3)(cid:48)(cid:85)(cid:74)(cid:83)(cid:92)(cid:75)(cid:76)(cid:90)(cid:3)(cid:11)(cid:24)(cid:24)(cid:27)(cid:3)(cid:84)(cid:80)(cid:83)(cid:83)(cid:80)(cid:86)(cid:85)(cid:3)(cid:51)(cid:59)(cid:58)(cid:40)(cid:3)(cid:196)(cid:85)(cid:72)(cid:85)(cid:74)(cid:76)(cid:75)(cid:3)(cid:74)(cid:72)(cid:87)(cid:80)(cid:91)(cid:72)(cid:83)(cid:3)(cid:76)(cid:95)(cid:87)(cid:76)(cid:85)(cid:75)(cid:80)(cid:91)(cid:92)(cid:89)(cid:76)(cid:90)(cid:21)
(cid:15)(cid:75)(cid:16)(cid:3)(cid:48)(cid:85)(cid:74)(cid:83)(cid:92)(cid:75)(cid:76)(cid:90)(cid:3)(cid:80)(cid:85)(cid:93)(cid:76)(cid:90)(cid:91)(cid:84)(cid:76)(cid:85)(cid:91)(cid:90)(cid:3)(cid:80)(cid:85)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:87)(cid:89)(cid:86)(cid:74)(cid:76)(cid:76)(cid:75)(cid:90)(cid:3)(cid:77)(cid:89)(cid:86)(cid:84)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:85)(cid:92)(cid:74)(cid:83)(cid:76)(cid:72)(cid:89)(cid:3)(cid:75)(cid:76)(cid:74)(cid:86)(cid:84)(cid:84)(cid:80)(cid:90)(cid:90)(cid:80)(cid:86)(cid:85)(cid:80)(cid:85)(cid:78)(cid:3)(cid:91)(cid:89)(cid:92)(cid:90)(cid:91)(cid:3)(cid:77)(cid:92)(cid:85)(cid:75)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:86)(cid:91)(cid:79)(cid:76)(cid:89)(cid:3)(cid:85)(cid:76)(cid:91)(cid:3)(cid:80)(cid:85)(cid:93)(cid:76)(cid:90)(cid:91)(cid:80)(cid:85)(cid:78)(cid:3)(cid:74)(cid:72)(cid:90)(cid:79)(cid:3)(cid:197)(cid:86)(cid:94)(cid:90)(cid:21)

   
   
   
   
   
   
   
   
   
   
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018

— OR —

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-38086

Vistra Energy Corp.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)

36-4833255
(I.R.S. Employer Identification No.)

6555 Sierra Drive, Irving, Texas 75039
(Address of principal executive offices) (Zip Code)

(214) 812-4600
(Registrant's telephone number, including area code)

__________________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class
Common stock, par value $0.01 per share
Warrants, exercisable for common stock at an exercise price of $35
per 0.652 share
7.00% tangible equity units

Name of Each Exchange on Which Registered
New York Stock Exchange
New York Stock Exchange

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None
__________________________________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in rule 405 of the Securities Act.   Yes 

  No

Indicated by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the act.   Yes

  No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act 
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject 
to such filing requirements for the past 90 days.   Yes 

  No

uu

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 
405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to
submit such files).   Yes

  No

d

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained 
herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company 
or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging 
growth company" in Rule 12b-2 of the Exchange Act.

nn

Large accelerated filer 

Accelerated filer 

N
Non-Accelerated filer 

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying 
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

ff

As  of  June  30,  2018,  the  aggregate  market  value  of  the  Vistra  Energy  Corp.  common  stock  held  by  non-affiliates  of  the  registrant  was 
$8,592,448,694 based on the closing sale price as reported on the New York Stock Exchange.

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes

  No 

As of February 25, 2019, there were 485,894,408 shares of common stock, par value $0.01, outstanding of Vistra Energy Corp.

________________________________________________________________________________
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the registrant's 2019 annual meeting of stockholders are incorporated in Part III of this Annual Report on
Form 10 K.

TABLE OF CONTENTS

PART I.

BUSINESS
RISK FACTORS
UNRESOLVED STAFF COMMENTS
PROPERTIES
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES

PART II.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER 
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
SELECTED FINANCIAL DATA

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 
RESULTS OF OPERATIONS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION

PART III.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR 
INDEPENDENCE

PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY

PAGE

ii

1
17
36
37
39
39

40

42
43

79
85
181

181
182

183
183
183

183

183

184
193
194

Glossary

Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.

Item 5.

Item 6.
Item 7.

Item 7A.
Item 8.
Item 9.

Item 9A.
Item 9B.

Item 10.
Item 11.
Item 12.

Item 13.

Item 14.

Item 15.
Item 16.
Signatures

Vistra Energy Corp.'s (Vistra Energy) annual reports, quarterly reports, current reports and any amendments to those reports are made
available to the public, free of charge, on the Vistra Energy website at http://www.vistraenergy.com, as soon as reasonably practicable 
after they have been filed with or furnished to the Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities 
Exchange Act of 1934, as amended.  Additionally, Vistra Energy posts important information, including press releases, investor presentations, 
sustainability reports, and notices of upcoming events on its website and utilizes its website as a channel of distribution to reach public investors
and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD.  Investors may
be notified of posting to the website by signing up for email alerts and RSS feeds on the "Investor Relations" page of Vistra Energy's website.  
The information on Vistra Energy's website shall not be deemed a part of, or incorporated by reference into, this annual report on Form 
10-K.  The representations and warranties contained in any agreement that we have filed as an exhibit to this annual report on Form 10-
K, or that we have or may publicly file in the future, may contain representations and warranties that may (i) be made by and to the parties
thereto at specific dates, (ii) be subject to exceptions and qualifications contained in separate disclosure schedules, (iii) represent the
parties' risk allocation in the particular transaction, or (iv) be qualified by materiality standards that differ from what may be viewed as
material for securities law purposes.

y

t

This annual report on Form 10-K and other Securities and Exchange Commission filings of Vistra Energy and its subsidiaries occasionally
make references to Vistra Energy (or "we," "our," "us" or "the Company"), Luminant, TXU Energy, Value Based Brands LLC, Dynegy
Energy Services or Homefield Energy when describing actions, rights or obligations of their respective subsidiaries.  These references 
reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, their respective parent company's financial statements
for  financial  reporting  purposes.    However,  these  references  should  not  be  interpreted  to  imply  that  the  parent  company  is  actually 
undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

a

ff

i

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

GLOSSARY

2017 Form 10-K

ARO

CAA

CAISO

CCGT

CFTC

Chapter 11 Cases

CME
CO2
Contributed EFH Debtors
CT

DIP Facility

DIP Roll Facilities

Debtors

Dynegy
Dynegy Energy Services

EBITDA

EFCH

Effective Date

EFH Corp.

EFH Debtors

EFIH

Emergence

EPA

Exchange Act
ERCOT
Federal and State Income Tax
Allocation Agreements

Vistra Energy's annual report on Form 10-K for the year ended December 31, 2017, filed with
the SEC on February 26, 2018, except for Part II, Items 7 and 8, which were amended in Vistra
Energy's current report on Form 8-K filed with the SEC on June 15, 2018

asset retirement and mining reclamation obligation

Clean Air Act

The California Independent System Operator

combined cycle gas turbine

U.S. Commodity Futures Trading Commission

Cases  in  the  U.S.  Bankruptcy  Court  for  the  District  of  Delaware  (Bankruptcy  Court) 
concerning  voluntary  petitions  for  relief  under  Chapter  11  of  the  U.S.  Bankruptcy  Code
(Bankruptcy Code) filed on April 29, 2014 by the Debtors.  On the Effective Date, the TCEH
Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases.

Chicago Mercantile Exchange

carbon dioxide

certain EFH Debtors that became subsidiaries of Vistra Energy on the Effective Date
combustion turbine
TCEH's $3.375 billion debtor-in-possession financing facility, which was repaid in August 
2016 (see Note 14 to the Financial Statements)

TCEH's  $4.250  billion  debtor-in-possession  and  exit  financing  facilities,  which  were 
converted to the Vistra Operations Credit Facilities on the Effective Date (see Note 14 to the 
Financial Statements)

EFH Corp. and the majority of its direct and indirect subsidiaries, including EFIH, EFCH and 
TCEH but excluding the Oncor Ring-Fenced Entities.  Prior to the Effective Date, also included 
the TCEH Debtors and the Contributed EFH Debtors.

Dynegy Inc., and/or its subsidiaries, depending on context

Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (d/b/a Dynegy and 
Brighten  Energy), indirect,  wholly  owned  subsidiaries  of Vistra Energy, that  are  REPs  in 
certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity 
to residential and business customers.

earnings (net income) before interest expense, income taxes, depreciation and amortization

Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of 
EFH Corp. and, prior to the Effective Date, the indirect parent of the TCEH Debtors, depending 
on context

October 3, 2016, the date the TCEH Debtors and the Contributed EFH Debtors completed 
their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases

Energy Future Holdings Corp. and/or its subsidiaries, depending on context, whose major 
subsidiaries include Oncor and, prior to the Effective Date, included the TCEH Debtors and 
the Contributed EFH Debtors

EFH Corp. and its subsidiaries that are Debtors in the Chapter 11 Cases, including EFIH and 
EFIH Finance Inc., but excluding the TCEH Debtors and the Contributed EFH Debtors

Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of 
EFH Corp. and the direct parent of Oncor Holdings

emergence of the TCEH Debtors and the Contributed EFH Debtors from the Chapter 11 Cases 
as subsidiaries of a newly formed company, Vistra Energy, on the Effective Date

U.S. Environmental Protection Agency

Exchange Act of 1934, as amended
Electric Reliability Council of Texas, Inc.
An agreement, executed in May 2012 but effective as of January 2010 to which prior to the 
Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH, EFIH and TCEH, 
but not including Oncor Holdings and Oncor) were parties.  The Agreement was rejected by 
the TCEH Debtors and the Contributed EFH Debtors on the Effective Date (see Note 9 to the 
Financial Statements).

ii

Fitch

GAAP

GHG

GWh
Homefield Energy

ICE

IRS

ISO

ISO-NE

kW

LIBOR

load

LSTC

LTSA

Luminant

market heat rate

Merger

Merger Agreement

Merger Date

MISO
MMBtu

Moody's

MSHA

MW

MWh
NERC
NOX
NRC

NYMEX

NYSE

NYISO

Oncor

Oncor Holdings

U.S. Federal Energy Regulatory Commission

Fitch Ratings Inc. (a credit rating agency)

generally accepted accounting principles

greenhouse gas

gigawatt-hours
Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned 
subsidiary of Vistra Energy, a REP in certain areas of MISO that is engaged in the retail sale 
of electricity to municipal customers

IntercontinentalExchange

U.S. Internal Revenue Service

independent system operator

Independent System Operator New England

kilowatt

London  Interbank  Offered  Rate,  an  interest  rate  at  which  banks  can  borrow  funds,  in
marketable size, from other banks in the London interbank market

demand for electricity

liabilities subject to compromise

long term service agreements for plant maintenance

subsidiaries of Vistra Energy engaged in competitive market activities consisting of electricity 
generation and wholesale energy sales and purchases as well as commodity risk management

Heat rate is a measure of the efficiency of converting a fuel source to electricity.  Market heat 
rate is the implied relationship between wholesale electricity prices and natural gas prices and 
is calculated by dividing the wholesale market price of electricity, which is based on the price 
offer of the marginal supplier (generally natural gas plants), by the market price of natural 
gas.

the  merger  of  Dynegy  with  and  into  Vistra  Energy,  with  Vistra  Energy  as  the  surviving
corporation
the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra 
Energy and Dynegy, as it may be amended or modified from time to time

April 9, 2018, the date Vistra Energy and Dynegy completed the transactions contemplated 
by the Merger Agreement

Midcontinent Independent System Operator, Inc.

million British thermal units

Moody's Investors Service, Inc. (a credit rating agency)

U.S. Mine Safety and Health Administration

megawatts
megawatt-hours

North American Electric Reliability Corporation

nitrogen oxide

U.S. Nuclear Regulatory Commission

the New York Mercantile Exchange, a commodity derivatives exchange

New York Stock Exchange

New York Independent System Operator

Oncor  Electric  Delivery  Company  LLC,  a  direct,  majority-owned  subsidiary  of  Oncor 
Holdings and an indirect subsidiary of EFH Corp., that is engaged in regulated electricity 
transmission and distribution activities

Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH 
and the direct majority owner of Oncor, and/or its subsidiaries, depending on context

Oncor Ring-Fenced Entities

Oncor Holdings and its direct and indirect subsidiaries, including Oncor

OPEB

postretirement employee benefits other than pensions

iii

Petition Date

PJM

Plan of Reorganization

PrefCo

PrefCo Preferred Stock Sale

PUCT

PURA

REP

RCT

RTO

S&P

SEC

Securities Act

SG&A

Settlement Agreement

SO2
Spin-Off

Sponsor Group

April 29, 2014, the date the Debtors filed voluntary petitions for relief under Chapter 11 of 
the United States Bankruptcy Code

PJM Interconnection, LLC

Third  Amended  Joint  Plan  of  Reorganization  filed  by  the  Debtors  in  August  2016  and 
confirmed by the Bankruptcy Court in August 2016 solely with respect to the TCEH Debtors 
and the Contributed EFH Debtors
Vistra Preferred Inc.

as part of the Spin-Off, the contribution of certain of the assets of the Predecessor and its
subsidiaries by a subsidiary of TEX Energy LLC to PrefCo in exchange for all of PrefCo's 
authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
Public Utility Commission of Texas

Texas Public Utility Regulatory Act

retail electric provider

Railroad Commission of Texas, which among other things, has oversight of lignite mining 
activity in Texas

regional transmission organization

Standard & Poor's Ratings (a credit rating agency)

U.S. Securities and Exchange Commission

Securities Act of 1933, as amended

selling, general and administrative

Amended and Restated Settlement Agreement among the Debtors, the Sponsor Group, settling 
TCEH  first  lien  creditors,  settling  TCEH  second  lien  creditors,  settling  TCEH  unsecured 
creditors and the official committee of unsecured creditors of TCEH (collectively, the Settling
Parties), approved by the Bankruptcy Court in December 2015.

sulfur dioxide

the tax-free spin-off from EFH Corp. executed pursuant to the Plan of Reorganization on the 
Effective Date by the TCEH Debtors and the Contributed EFH Debtors
Refers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts & 
Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, an 
affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Energy Future 
Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that 
owns substantially all of the common stock of EFH Corp.

ST

steam turbine

Tax Matters Agreement

Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., EFIH, 
EFIH Finance Inc. and EFH Merger Co. LLC.

TCJA

TRA

TRE

TCEH or Predecessor

TCEH Debtors
TCEH Senior Secured
Facilities

The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, 
which significantly changed the tax laws applicable to business entities

Tax Receivables Agreement, containing certain rights (TRA Rights) to receive payments from 
Vistra Energy related to certain tax benefits, including those it realized as a result of certain 
transactions entered into at Emergence (see Note 10)

Texas Reliability Entity, Inc., an independent organization that develops reliability standards 
for  the  ERCOT  region  and  monitors  and  enforces  compliance  with  NERC  standards  and 
monitors compliance with ERCOT protocols
Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of 
Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the 
parent company of the TCEH Debtors, depending on context, that were engaged in electricity 
generation and wholesale and retail energy market activities, and whose major subsidiaries 
included Luminant and TXU Energy

the subsidiaries of TCEH that were Debtors in the Chapter 11 Cases

Refers, collectively, to the TCEH First Lien Term Loan Facilities, TCEH First Lien Revolving 
Credit Facility and TCEH First Lien Letter of Credit Facility with a total principal amount of 
$22.616 billion.  The claims arising under these facilities were discharged in the Chapter 11 
Cases on the Effective Date pursuant to the Plan of Reorganization.

TCEQ

Texas Commission on Environmental Quality

iv

TXU Energy

U.S.

Value Based Brands

Vistra Energy or Successor

Vistra Operations

TXU Energy Retail Company LLC, an indirect, wholly owned subsidiary of Vistra Energy
that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to 
residential and business customers

United States of America

Value Based Brands LLC (d/b/a 4Change Energy and Express Energy), an indirect, wholly 
owned subsidiary of Vistra Energy that is a REP in competitive areas of ERCOT and is engaged 
in the retail sale of electricity to residential and business customers

Vistra Energy Corp., formerly known as TCEH Corp., and/or its subsidiaries, depending on 
context.  On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors emerged 
from Chapter 11 and became subsidiaries of Vistra Energy Corp.
Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra Energy that 
is the issuer of certain series of notes (see Note 14 to the Financial Statements) and borrower 
under the Vistra Operations Credit Facilities

Vistra Operations Credit
Facilities

Vistra Operations Company LLC's $8.313 billion senior secured financing facilities (see Note 
14 to the Financial Statements)

v

Item 1.  BUSINESS

PART I

References in this report to "we," "our," "us" and "the Company" are to Vistra Energy and/or its subsidiaries, as apparent in 

the context.  See Glossary for defined terms.

Business

Vistra Energy is a holding company operating an integrated retail and generation business in markets throughout the U.S.  
Through our subsidiaries, we are engaged in competitive electricity market activities including electricity generation, wholesale 
energy sales and purchases, commodity risk management and retail sales of electricity to end users.

We serve approximately 2.8 million customers in five states.  Our generation fleet totals approximately 40,500 MW of 

generation capacity with a portfolio of natural gas, nuclear, coal and solar facilities.

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), 
(v) MISO and (vi) Asset Closure.  The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets 
served by businesses acquired in the Merger.  See Note 22 to the Financial Statements for further information concerning reportable 
business segments.

As of December 31, 2018, we had approximately 5,275 full-time employees, including approximately 2,030 employees under 

collective bargaining agreements.

Merger

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement.  Pursuant 
to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. 
See Note 2 to the Financial Statements for a summary of the Merger transaction and business combination accounting.

Business Strategy

Our business strategy is to deliver long-term stakeholder value through a focus on the following areas:

• 

Integrated business model.  We believe the key factor that distinguishes us from others in the competitive electricity
industry is the integrated nature of our business (i.e., pairing our reliable and efficient mining, diversified generation
fleet and wholesale commodity risk management capabilities with our retail platform).  Our business strategy will be 
guided by our integrated business model because we believe it is our core competitive advantage and differentiates us
from our non-integrated competitors.  We believe our integrated business model creates a unique opportunity because, 
relative to our non-integrated competitors, it reduces the effects of commodity price movements and contributes to 
earnings and cash flow stability.  Consequently, our integrated business model is at the core of our business strategy.

•  Disciplined capital allocation.  Vistra takes a balanced approach to capital allocation, focusing on maintaining a strong
balance  sheet,  investing  prudently  in  the  maintenance  of  our  existing  assets  and  potential  growth  acquisitions,  and 
returning capital to shareholders.  Maintaining a strong balance sheet ensures Vistra’s interest expense is manageable
in a variety of wholesale power price environments while giving Vistra access to flexible and diverse sources of liquidity.    
We prudently make necessary capital investments to maintain the safety and reliability of our facilities while also investing
in  new  technologies  when  economic,  including  solar  assets  and  battery  storage  systems,  resulting  in  a  continued 
modernization of Vistra’s generation fleet.  Because we believe cost discipline and strong management of our assets and 
commodity positions are necessary to deliver long-term value to our stakeholders, we generally make capital allocation 
decisions  that  we  believe  will  lead  to  attractive  cash  returns  on  investment,  including  by  returning  capital  to  our 
shareholders.  In June and November 2018, our board of directors (Board) authorized a share repurchase program under 
which up to $500 million and $1.25 billion, respectively, of our outstanding common stock may be repurchased.  Through 
December 31, 2018, 33,495,016 shares of our common stock had been repurchased under the program in the aggregate
for $778 million (including related fees and expenses) at an average price per share of common stock of $23.23.  In 
November 2018, our Board adopted a dividend program pursuant to which we expect to initiate an annual dividend of 
approximately $0.50 per share, payable quarterly, beginning in the first quarter of 2019.

1

• 

•

•

•

Superior  customer  service.  Through  TXU  Energy  and  Value  Based  Brands  in  Texas,  Dynegy  Energy  Services  in
Massachusetts, Ohio, Illinois and Pennsylvania and Homefield Energy in Illinois, we serve the retail electricity needs
of  end-use  residential,  small  business,  commercial  and  industrial  electricity  customers  through  multiple  sales  and 
marketing  channels.    In  addition  to  benefitting  from  our  integrated  business  model,  we  leverage  our  brands,  our 
commitment to a consistent and reliable product offering, the backstop of the electricity generated by our generation 
fleet, our wholesale commodity risk management operations and our strong customer service to differentiate our products 
and services from our competitors.  We strive to be at the forefront of innovation with new offerings and customer 
experiences  to  reinforce  our  value  proposition.   We  maintain  a  focus  on  solutions  that  give  our  customers  choice, 
convenience and control over how and when they use electricity and related services, including TXU Energy's Free 
Nights  and  Solar  Days  residential  plans,  MyEnergy  DashboardSM,  TXU  Energy's  iThermostat  product  and  mobile
solution, the TXU Energy Rewards program, the TXU Energy Green UpSM renewable energy credit program and a
diverse set of solar options.  Our focus on superior customer service will guide our efforts to acquire new residential 
and commercial customers, serve and retain existing customers and maintain valuable sales channels for our electricity
generation  resources.    We  believe  our  customer  service,  products  and  trusted  TXU  Energy  brand  have  resulted  in 
maintaining the highest residential customer retention rate of any Texas retail electric provider in its respective core 
market.

Excellence in operations while maintaining an efficient cost structure.  We believe that operating our facilities in a safe, 
reliable, environmentally compliant, and cost-effective and efficient manner is a foundation for delivering long-term
stakeholder value.  We also believe value increases as a function of making disciplined investments that enable our 
generation facilities to operate not only effectively and efficiently, but also safely, reliably and in an environmentally 
compliant manner.  We believe that an ongoing focus on operational excellence and safety is a key component to success
in a highly competitive environment and is part of the unique value proposition of our integrated model.  Additionally, 
we are committed to optimizing our cost structure, reducing our debt levels and implementing enterprise-wide process 
and  operating  improvements  without  compromising  the  safety  of  our  communities,  customers  and  employees.   We
believe we have a highly effective and efficient cost structure and that our cost structure supports excellence in our 
operations.

Integrated  hedging  and  commercial  management.    Our  commercial  team  is  focused  on  managing  risk,  through
opportunistic hedging, and optimizing our assets and business positions.  We actively manage our exposure to wholesale 
electricity prices in markets in which we operate, on an integrated basis, through contracts for physical delivery of 
electricity, exchange-traded and over-the-counter financial contracts, term, day-ahead and real-time market transactions,
and bilateral contracts with other wholesale market participants, including other power generators and end-user electricity 
customers.  These hedging activities include short-term agreements, long-term electricity sales contracts and forward 
sales of natural gas through financial instruments.  The historically positive correlation between natural gas prices and 
wholesale  electricity  prices  has  provided  us  an  opportunity  to  manage  our  exposure  to  the  variability  of  wholesale
electricity prices through natural gas hedging activities.  We seek to hedge near-term cash flow and optimize long term
value through hedging and forward sales contracts.  We believe our integrated hedging and commercial management 
strategy, in combination with a strong balance sheet and strong liquidity profile, will provide a long-term advantage 
through cycles of higher and lower commodity prices.

Growth and enhancement.  Our growth strategy leverages our core capabilities of multi-channel retail marketing in a
large and competitive market, operating large-scale, environmentally sensitive, and diverse assets across a variety of 
fuel technologies, fuel logistics and management, commodity risk management, cost control, and energy infrastructure 
investing.  We intend to opportunistically evaluate acquisitions of high-quality energy infrastructure assets and businesses
that complement these core capabilities and enable us to achieve operational or financial synergies.  We are also focused 
on enhancing our retail platform in markets outside of Texas, including our recently announced entry into a purchase 
agreement to acquire Crius Energy Trust discussed below.  While we are intent on growing our business and creating
value for our stockholders, we are committed to making disciplined investments that are consistent with our focus on
maintaining  a  strong  balance  sheet  and  strong  liquidity  profile.   As  a  result,  consistent  with  our  disciplined  capital
allocation approval process, growth opportunities we pursue will need to have compelling economic value in addition
to fitting with our business strategy.

2

•

Corporate  responsibility  and  citizenship.  We  are  committed  to  providing  safe,  reliable,  cost-effective  and 
environmentally compliant electricity for the communities and customers we serve.  We strive to improve the quality 
of life in the communities in which we operate.  We are also committed to being a good corporate citizen in the communities 
in which we conduct operations.  We and our employees are actively engaged in programs intended to support and 
strengthen the communities in which we conduct operations.  Our foremost giving initiatives are through the United 
Way and TXU Energy Aid campaigns.  TXU Energy Aid has served as an integral resource for social service agencies 
that assist families in need across Texas pay their electricity bills.

Recent Developments

Entry into Purchase Agreement to Acquire Crius Energy Trust — On February 7, 2019, Vistra Energy and Crius Energy Trust 
(Crius)  entered  into  a  definitive  agreement,  which  was  subsequently  amended  on  February  19,  2019  (as  amended,  the  Crius 
Purchase Agreement), as a result of an unsolicited acquisition proposal, pursuant to which Vistra Energy will acquire the equity tt
interest of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction).  Crius
is an energy retailer selling both electricity and natural gas products to residential and small business customers in 19 states and 
the District of Columbia.

The acquisition provides a high degree of overlap with Vistra Energy's generation fleet and contains approximately 11.6 
TWh of annual load, improving Vistra Energy's match of its generation to load profile to approximately 45 percent, reducing risk. 
The acquisition also establishes a platform for future growth by leveraging Vistra Energy's existing retail marketing capabilities
and  Crius's  experienced  team.    The  acquisition  enhances  the  integrated  value  proposition  through  collateral  and  transaction 
efficiencies, particularly via Crius's largely retail portfolio.

Vistra Energy intends to fund the purchase price of approximately $378 million using cash on hand and assumption of Crius's 
net debt of approximately $108 million.  Completion of the Crius Transaction is subject to various customary conditions, including,
among others, (i) approval by at least two-thirds of the Crius unitholders and (ii) receipt of all requisite regulatory approvals, which
include approvals of the FERC and the expiration and termination of the applicable waiting period under the Hart-Scott-Rodino 
Antitrust Improvements Act of 1976.  Pending the receipt of all necessary approvals and the fulfillment of all other customary
closing conditions, the parties expect the transaction to close in the second quarter of 2019.

Dividend Declaration — On February 26, 2019, Vistra Energy announced that the Board had declared a dividend pursuant 
to which Vistra Energy would pay, to each holder of record as of March 15, 2019, a dividend of $0.125 per share, to be paid March 
29, 2019.

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

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

Market Discussion

The operations of Vistra Energy are aligned into six reportable business segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/
NE, (v) MISO and (vi) Asset Closure.  The Retail segment is engaged in retail sales of electricity and related services to residential, 
commercial and industrial customers.  The ERCOT, PJM, NY/NE (comprising NYISO and ISO-NE) and MISO segments are
engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production 
and fuel logistics management, all largely within their respective RTO or ISO market.  The Asset Closure segment is engaged in
the decommissioning and reclamation of retired plants and mines.  Our CAISO operations are included in the Corporate and Other 
non-segment as our operations in the CAISO market do not materially affect our financial condition, results of operations and 
cash flows.  See Note 22 to the Financial Statements for additional information related to our operating segments.

3

Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)

Separately, RTOs and ISOs administer the transmission infrastructure and markets across a regional footprint in most of the 
markets in which we operate.  They are responsible for dispatching all generation facilities in their respective footprints and are 
responsible for both maximum utilization and reliable and efficient operation of the transmission system.  RTOs and ISOs administer 
energy and ancillary service markets in the short term, usually day-ahead and real-time markets.  Several RTOs and ISOs also 
ensure long-term planning reserves through monthly, semiannual, annual and multiyear capacity markets.  The RTOs and ISOs 
that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to impose, bid 
and price limits or other similar mechanisms. NERC regions and RTOs/ISOs often have different geographic footprints, and while 
there may be geographic overlap between NERC regions and RTOs/ISOs, their respective roles and responsibilities do not generally 
overlap.

d

In RTO and ISO regions with centrally dispatched market structures, all generators selling into the centralized market receive
the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance 
supply with demand within a designated zone or at a given location.  Different zones or locations within the same RTO/ISO may 
produce  different  prices  respective  to  other  zones  within  the  same  RTO/ISO  due  to  transmission  losses  and  congestion.    For 
example, a less efficient and/or less economical natural gas-fueled unit may be needed in some hours to meet demand.  If this
unit's production is required to meet demand on the margin, its offer price will set the market clearing price that will be paid for 
all dispatched generation in the same zone or location (although the price paid at other zones or locations may vary because of
transmission losses and congestion), regardless of the price that any other unit may have offered into the market.  In RTO and ISO
regions with centrally dispatched market structures and location-based marginal price clearing structures (e.g. PJM, ISO-NE, 
NYISO, ERCOT, MISO, and CAISO), generators will receive the location-based marginal price for their output. The location-
based marginal price, absent congestion, would be the marginal price of the most expensive unit needed to meet demand.  In
regions that are outside the footprint of RTOs/ISOs, prices are determined on a bilateral basis between buyers and sellers.

Retail Markets

The Retail segment is engaged in retail sales of electricity and related services to approximately 2.8 million customers. 
Substantially all of these activities are conducted by TXU Energy and Value Based Brands in Texas, Dynegy Energy Services in 
Massachusetts, Ohio, Illinois and Pennsylvania and Homefield Energy in Illinois.

The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 1.7 million
customers in ERCOT.  We are an active participant in the competitive ERCOT retail market and continue to be a market leader, 
which we believe is driven by, among other things, having one of the lowest customer complaint rates according to the PUCT and 
having an integrated power generation and wholesale operation that allows us to efficiently obtain the electricity needed to serve 
our customers at the lowest cost.  As of December 31, 2018, we provided electricity to approximately 23% and 20% of the residential
and commercial customers in ERCOT, respectively.  We believe that we have differentiated ourselves by providing a distinctive 
customer experience predicated on delivering reliable and innovative power products and solutions to our customers, such as Free
Nights and Solar Days residential plans, MyEnergy DashboardSM, TXU iThermostat product and mobile solution, the TXU Energy
Rewards program, the TXU Energy Green UPSM renewable energy credit program and a diverse set of solar options, which give
our customers choice, convenience and control over how and when they use electricity and related services.  We competitively 
market electricity and related services to acquire, serve and retain retail customers.  We believe we are situated to better serve our 
retail  customers  through  our  unique  affiliation  with  our  wholesale  commodity  risk  management  personnel  who  can  structure 
products and contracts in a way that offers significant value compared to stand-alone retail electric providers.  Additionally, our 
wholesale commodity risk management operations protect our retail business from power price volatility by allowing us to bypass
bid-ask spread in the market (particularly for illiquid products and time periods), which results in significantly lower collateral
costs for our retail business as compared to other, non-integrated retail electric providers.  Moreover, our retail business reduces, 
to some extent, the exposure of our wholesale generation business to wholesale power price volatility.  This is because the retail
load requirements of our retail operations (primarily TXU Energy) provide a natural offset to the length of Luminant's generation
portfolio thereby reducing the exposure to wholesale power price volatility as compared to a non-integrated independent power 
producer.

We also serve residential, municipal, commercial and industrial customers through our Homefield Energy and Dynegy Energy 
Services  retail  businesses,  through  which  we  provide  retail  electricity  to  approximately  1.1  million  customers  in  Illinois, 
Massachusetts, Ohio and Pennsylvania.

4

ERCOT Market

ERCOT is an ISO that manages the flow of electricity from approximately 78,000 MW of installed capacity to approximately 

25 million Texas customers, representing approximately 90% of the state's electric load.

As an energy-only market, ERCOT's market design is distinct from other competitive electricity markets in the U.S.  Other 
markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/or capacity
markets.    In  contrast,  ERCOT's  resource  adequacy  is  predominately  dependent  on  energy-market  price  signals.    ERCOT 
implemented  the  Operating  Reserve  Demand  Curve  (ORDC),  pursuant  to  which  wholesale  electricity  prices  in  the  real-time
electricity market increase automatically as available operating reserves decrease below defined threshold levels, creating a price 
adder.  When operating reserves drop to 2,000 MW or less, the ORDC automatically adjusts power prices to the established value
of lost load (VOLL), which is set at $9,000/MWh.  Because ERCOT has limited excess generation capacity to meet high demand 
days due to its minimal import capacity, and peaking facilities have high operating costs, the marginal price of supply rapidly
increases during periods of high demand.  Historically, elevated temperatures in the summer months have driven high electricity
demand in ERCOT.  Many generators benefit from these sporadic periods of "scarcity pricing" in which power prices may increase 
significantly, up to the current $9,000/MWh price cap.

Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market.  The day-ahead 
market is a voluntary, forward electricity market conducted the day before each operating day in which generators and purchasers
of electricity may bid for one or more hours of electricity supply or consumption.  The real-time market is a spot market in which 
electricity may be sold in five-minute intervals.  The day-ahead market provides market participants with visibility into where
prices are expected to clear, and the prices are not impacted by subsequent events.  Conversely, the real-time market exposes
purchasers to the risk of transient operational events and price spikes.  These two markets allow market participants to manage
their risk profile by adjusting their participation in each market.  In addition, ERCOT uses ancillary services to maintain system 
reliability, including regulation service-up, regulation service-down, responsive reserve service and non-spinning reserve service.  
Regulation service up and down are used to balance the grid in a near-instantaneous fashion when supply and demand fluctuate
due to a variety of factors, such as weather, generation outages, renewable production intermittency and transmission outages. 
Responsive reserves and non-spinning reserves are used by ERCOT when the grid is at, near or recovering from a state of emergency 
due to inadequate generation.  Because ERCOT has one of the highest concentrations of wind capacity generation among U.S.
markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind production, 
making ERCOT more vulnerable to periods of generation scarcity.

Our ERCOT segment is comprised of 20 power generation facilities located in Texas totaling 18,366 MW of generation 
capacity.  Our ERCOT fleet includes seven CCGT natural gas-fueled generation facilities totaling 7,838 MW, three lignite/coal-
fueled generation facilities totaling 4,500 MW, eight natural gas-fueled peaking generation facilities totaling 3,538 MW, a nuclear 
generation facility totaling 2,300 MW, a solar photovoltaic power generation facility totaling 180 MW and a battery energy storage 
system totaling 10 MW.

PJM Market

PJM is an RTO that manages the flow of electricity from approximately 178,000 MW of generation capacity to approximately 
65 million customers in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina,
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing a locational
marginal pricing (LMP) methodology which calculates a price for every generator and load point within PJM.  This market is
transparent, allowing generators and load serving entities to see real-time price effects, transmission constraints and the impacts
of congestion at each pricing point.  PJM operates day-ahead and real-time markets into which generators can bid to provide energy
and ancillary services.  PJM also administers a forward capacity auction, the Reliability Pricing Model (RPM), which establishes
long-term markets for capacity.  We have participated in RPM base residual auctions for years up to and including PJM's planning 
year 2021-2022, which ends May 31, 2022.  We also enter into bilateral capacity transactions.  PJM's Capacity Performance (CP) 
rules are designed to improve system reliability and include penalties for under-performing units and reward for over-performing 
units during shortage events.  PJM's base capacity resources are those capacity resources not capable of sustained, predictable
operation throughout the entire delivery year, but can provide energy and reserves during hot weather operations.  The base capacity 
resources are subject to non-performance charges assessed during emergency conditions from June through September.  Full 
transition of the capacity market to CP rules will occur by planning year 2020-2021.  An independent market monitor continually
monitors PJM markets to ensure a robust, competitive market and to identify an improper behavior by any entity.

5

Our PJM segment is comprised of 17 power generation facilities totaling 10,769 MW of generating capacity.  Our PJM fleet 
includes eight CCGT natural gas-fueled generation facilities totaling 5,902 MW, three coal-fueled generation facilities totaling 
3,428 MW and six natural gas- or oil-fueled generation facilities totaling 1,439 MW.  Of these facilities, eight are located in Ohio,
three in Pennsylvania, three in Illinois and one each in New Jersey, Virginia and West Virginia.

n

NYISO and ISO-NE Markets

NYISO is an ISO that manages the flow of electricity from approximately 39,000 MW of generation capacity to approximately

20 million New York customers.

The NYISO market dispatches power plants to meet system energy and reliability needs and settles physical power deliveries
at LMPs.  Energy prices vary among the regional zones in the NYISO and are largely influenced by transmission constraints and 
fuel supply.  NYISO offers a forward capacity market where capacity prices are determined through auctions.  Strip auctions occur 
one to two months prior to the commencement of a six-month seasonal planning period.  Subsequent auctions provide an opportunitytt
to sell excess capacity for the balance of the seasonal planning period or the upcoming month.  Due to the short-term nature of
the NYISO-operated capacity auctions and a relatively liquid bilateral market for NYISO capacity products, our Independence
facility sells a significant portion of its capacity through bilateral transactions.  The balance is cleared through the seasonal and 
monthly capacity auctions.

ISO-NE is an ISO that manages the flow of electricity from approximately 31,000 MW of installed generation capacity to 
approximately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island and 
Maine.

 ISO-NE dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. 
Energy prices vary among the participating states in ISO-NE and are largely influenced by transmission constraints and fuel supply.  
ISO-NE offers a forward capacity market where capacity prices are determined through auctions.  Performance incentive rules 
went into effect for planning year 2018-2019 (FCA-9), which will have the potential to increase capacity payments for those
resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the 
required level.

t

Our NY/NE segment is comprised of eight CCGT natural gas-fueled generation facilities totaling 4,730 MW of generation 

capacity.  Of these facilities, four are located in Massachusetts, two in Connecticut and one each in Maine and New York.

MISO Market

MISO is an RTO that manages the flow of electricity from approximately 200,000 MW of installed capacity to approximately 
42 million customers in all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan, Kentucky, Indiana, Illinois, Missouri,
Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota and Manitoba, Canada.

The MISO energy market is designed to ensure that all market participants have open-access to the transmission system on
a non-discriminatory basis.  MISO, as an independent RTO, maintains functional control over the use of the transmission system
to ensure transmission circuits do not exceed their secure operating limits and become overloaded.  MISO operates day-ahead and
real-time energy markets using a similar LMP methodology as described above for the PJM market.  An independent market 
monitor is responsible for evaluating the performance of the markets and identifying conduct by market participants or MISO that 
may compromise the efficiency or distort the outcome of the markets.

MISO administers a one-year FCA for the next planning year from June 1st of the current year to May 31st of the following 
year.  We participate in these auctions with open capacity that has not been committed through bilateral or retail transactions.  We 
also participate in the MISO annual and monthly FTR auctions to manage the cost of our transmission congestion, as measured 
by the congestion component of the LMP price differential between two points on the transmission grid across the market area.

Our MISO segment is comprised of eight power generation facilities located in Illinois totaling 5,476 MW of generation 
capacity.  Joppa, which is within the Electric Energy, Inc. (EEI) control area, is interconnected to Tennessee Valley Authority and 
Louisville Gas and Electric Company, but primarily sells its capacity and energy to MISO.  We currently offer a portion of our 
MISO segment generating capacity and energy into PJM.  Our Coffeen, Duck Creek, Edwards and Newton generation facilities 
have 2,540 MW electrically tied into PJM through pseudo-tie arrangements.  Our Hennepin generation facility offers 294 MW of 
the facility's energy and capacity into PJM as a block schedule and began dispatching as a pseudo-tie unit for planning year 
2018-2019.

y

6

CAISO Market

CAISO is an ISO that manages the flow of electricity from approximately 60,000 MW of installed capacity to approximately 

30 million customers primarily in California, representing approximately 80% percent of the state's electric load.

Energy is priced utilizing an LMP methodology as described above.  The capacity market is comprised of Generic, Flexible 
and Local Resource Adequacy (RA) Capacity and is administered by the California Public Utilities Commission.  Unlike other 
centrally cleared capacity markets, the resource adequacy market in California is a bilaterally traded market.  In November 2016, 
CAISO implemented a voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in 
the market.  The voluntary Competitive Solicitation Process, which FERC approved in October 2015, is a modification to the 
Capacity  Procurement  Mechanism  (CPM)  and  provides  another  avenue  to  sell  RA  capacity.    There  have  been  recent  CPM
designations through the Competitive Solicitation Process.  These include Moss Landing Unit 1 for 510 MW for the calendar year 
2018 and Moss Landing Unit 2 intra-monthly designation for 29 MW for September through November 2018.

Our CAISO operations are comprised of two power generation facilities located in California totaling 1,185 MW of generating
capacity.    Our  CAISO  fleet  includes  one  CCGT  natural  gas-fueled  generation  facility  totaling  1,020  MW  and  one  oil-fueled 
generation facility totaling 165 MW.  In June 2018, we announced that we will enter into a 20-year resource adequacy contract 
with Pacific Gas and Electric Company (PG&E) to develop a 300 MW battery energy storage project at our Moss Landing Power 
Plant site in California.  PG&E filed its application with the California Public Utilities Commission (CPUC) in June 2018 and the 
CPUC approved the contract in November 2018.  We anticipate the battery storage project will enter commercial operations by 
the fourth quarter of 2020.

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Wholesale Operations

Our wholesale commodity risk management group is responsible for dispatching our generation fleet in response to market 
needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production with our 
retail customer and wholesale sales opportunities.  Market demand, also known as load, faced by electric power systems, such as
those we operate in, varies from moment to moment as a result of changes in business and residential demand, which is often
driven by weather.  Unlike most other commodities, the production and consumption of electricity must remain balanced on an 
instantaneous basis.  There is a certain baseline demand for electricity across an electric power system that occurs throughout the
day, which is typically satisfied by baseload generating units with low variable operating costs.  Baseload generating units can a
also increase output to satisfy certain incremental demand and reduce output when demand is unusually low.  Intermediate/load-
following generating units, which can more efficiently change their output to satisfy increases in demand, typically satisfy a large
proportion of changes in intraday load as they respond to daily increases in demand or unexpected changes in supply created by 
reduced generation from renewable resources or other generator outages.  Peak daily loads may be satisfied by peaking units. 
Peaking units are typically the most expensive to operate, but they can quickly start up and shut down to meet brief peaks in
demand.  In general, baseload units, intermediate/load following units and peaking units are dispatched into the RTO/ISO grid in 
order from lowest to highest variable cost.  Price formation is typically based on the highest variable cost unit that clears the market 
to satisfy system demand at a given point in time.

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Our commodity risk management group also enters into electricity, gas and other commodity derivative contracts to reduce 
exposure to changes in prices primarily to hedge future revenues and fuel costs for our generation facilities and purchased power 
costs for our Retail segment.

Seasonality

The demand for and market prices of electricity and natural gas are affected by weather.  As a result, our operating results
may fluctuate on a seasonal basis.  Typically, demand for and the price of electricity is higher in the summer and winter seasons,
when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter.  More 
severe weather conditions such as heat waves or extreme winter weather may make such fluctuations more pronounced.  However, 
not all regions of the U.S. typically experience extreme weather conditions at the same time, so Vistra Energy is typically not
exposed to the effects of extreme weather in all parts of its business at once.  The pattern of this fluctuation may change depending 
on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.

7

Competition

Competition in the markets in which we operate is impacted by electricity and fuel prices, congestion along the power grid, 
subsidies provided by state and federal governments for new and existing generation facilities, new market entrants, construction 
of new generating assets, technological advances in power generation, the actions of environmental and other regulatory authorities,
and other factors.  We primarily compete with other electricity generators and retailers based on our ability to generate electrictt
supply, market and sell electricity at competitive prices and to efficiently utilize transportation from third-party pipelines and 
transmission from electric utilities to deliver electricity to end-users.  Competitors in the generation and retail power markets in
which we participate include regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated 
utilities, independent power producers, REPs and other energy marketers.  See Item 1A. Risk Factors for additional information
concerning the risks faced with respect to the competitive energy markets in which we operate.

Brand Value

Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in 
Texas for approximately 17 years, is registered and protected by trademark law and is the only material intellectual property asset 
that we own.  As of December 31, 2018, we have reflected an intangible asset on our balance sheet for the TXU Energy brand of 
approximately $1.2 billion (see Note 8 to the Financial Statements).

Environmental Regulations and Related Considerations

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We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental
regulatory bodies of states in which we operate.  The EPA has recently finalized or proposed several regulatory actions establishing
new requirements for control of certain emissions from sources, including electricity generation facilities.  See Item 1A. Risk 
Factors for additional discussion of risks posed to us regarding regulatory requirements.  See Note 15 to the Financial Statements 
for a discussion of litigation related to EPA reviews.

Climate Change

There is a debate nationally and internationally about global climate change and how greenhouse gas (GHG) emissions, such 
as carbon dioxide (CO2), might contribute to global climate change.  GHG emissions from the combustion of fossil fuels, primarily 
by our coal/lignite-fueled-generation plants, represent the substantial majority of our total GHG emissions.  CO2, methane and 
nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions.  We
estimate that our generation facilities produced approximately 135 million short tons of CO2 in 2018.

Greenhouse Gas Emissions

In August  2015,  the  EPA  finalized  rules  to  address  GHG  emissions  from  new,  modified  and  reconstructed  and  existing 
electricity generation units, referred to as the Clean Power Plan, including rules for existing facilities that would establish state-
specific emissions rate goals to reduce nationwide CO2 emissions.  Various parties (including Luminant) filed petitions for review
in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court), and subsequently, in January 2016, a coalition 
of states, industry (including Luminant) and other parties filed applications with the U.S. Supreme Court (Supreme Court) asking
that the Supreme Court stay the rule while the D.C. Circuit Court reviews the legality of the rule for existing plants.  In February
2016, the Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and 
until the Supreme Court disposes of any subsequent petition for review.  Oral argument on the merits of the legal challenges to
the rule was heard in September 2016 before the entire D.C. Circuit Court, but the D.C. Circuit Court has not issued a decision
and the case remains in abeyance due to the EPA's decision to review the Clean Power Plan.

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8

In October 2017, the EPA issued a proposed rule that would repeal the Clean Power Plan with the proposed repeal focusing 
on  what  the  EPA  believes  to  be  the  unlawful  nature  of  the  Clean  Power  Plan  and  asking  for  public  comment  on  the  EPA's 
interpretations of its authority under the Clean Air Act.  In December 2017, the EPA published an advance notice of proposed 
rulemaking (ANPR) soliciting information from the public as the EPA considers proposing a future rule.  Vistra Energy submitted
comments on the ANPR in February 2018.  Vistra Energy submitted comments on the proposed repeal in April 2018.  In August 
2018, the EPA published a proposed replacement rule called the Affordable Clean Energy rule.  We submitted comments on the 
proposed Affordable Clean Energy rule in October 2018.  In December 2018, the EPA issued proposed revisions to the emission 
standards for new, modified and reconstructed units with comments due in March 2019.  While we cannot predict the outcome of 
these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately 
implemented or upheld as they were issued, they could have a material impact on our results of operations, liquidity or financial
condition.

State Regulation of GHGs

Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only 

regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change.

Regional Greenhouse Gas Initiative (RGGI) — RGGI is a state-driven GHG emission control program that took effect in
2009 and was initially implemented by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants. 
The  participating  RGGI  states  implemented  a  cap-and-trade  program.    Compliance  with  RGGI  can  be  achieved  by  reducing 
emissions, purchasing or trading allowances or securing offset allowances from an approved offset project.  We are required to 
hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period.

In December 2017, the RGGI states released an updated model rule with changes to the CO2 budget trading program, including 
an additional 30 percent reduction in the CO2 annual cap by the year 2030, relative to 2020 levels.  The RGGI cap on CO2 emissions
would decline by 2.275 million tons per year beginning in 2021.  Each RGGI state will work to ensure that its program changes
are in effect by 2021.

Our generating facilities in Connecticut, Maine, Massachusetts and New York emitted approximately 8.3 million tons of 
CO2 during 2018.  The spot market price of RGGI allowances required to operate these facilities as of December 31, 2018 was
approximately $5.39 per allowance.  The spot market price of RGGI allowances required to operate our affected facilities during
2019 was $5.40 per allowance on February 25, 2019.  While the cost of allowances required to operate our RGGI-affected facilities
is expected to increase in future years, we expect that the cost of compliance would be reflected in the power market, and the
actual impact to gross margin would be largely offset by an increase in revenue.

Massachusetts — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final 
rules establishing an annual declining limit on aggregate CO2 emissions from 21 in-state fossil-fueled electricity generation units. 
The rules establish an allowance trading system under which the annual aggregate electricity generation unit sector cap on CO2
emissions declines from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050.  MassDEP allocated emission allowances
to affected facilities for 2018.  Beginning in 2019, the allocation process will transition to a competitive auction process. Allowances
for 2019 and 2020 will be partially distributed through a competitive auction process and partially distributed based on the process
and schedule established by the rule.  Beginning in 2021, all allowances will be distributed through the auction.  Limited banking
of unused allowances is allowed.  The New England Power Generators Association, in which we are a member, and other generators
filed complaints in Massachusetts superior court challenging the rules.  In January 2018, the Massachusetts Supreme Judicial
Court decided to review the challenges to MassDEP's electricity generation unit's CO2 rules and transferred the case from the
superior court where the rule was upheld.  Based on current projections of operations for our Massachusetts generating facilities
in 2019, we anticipate that allocated allowances will cover CO2 emissions.  We expect the rules will have little or no near-term
impact on the financial results of our generating facilities in Massachusetts.  However, if upheld, the rules would have an adverse 
impact on the long-term future of these facilities.

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Virginia — In January 2018, the Virginia Department of Environmental Quality issued a proposed rule to adopt a carbon
cap-and trade program for fossil-fueled electricity generation units, including our Hopewell facility, beginning in 2020.  The
proposed program is based on the RGGI proposed 2017 model rule and is intended to link Virginia to RGGI.

New Jersey — In January 2018, the Governor of New Jersey signed an executive order directing the state's environmental
agency and public utilities board to begin the process of rejoining RGGI.  In December 2018, New Jersey published two rule
proposals that would establish the mechanisms for New Jersey to rejoin RGGI.

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California  —  Our  assets  in  California  are  subject  to  the  California  Global Warming  Solutions Act,  which  required  the
California Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state 
to 1990 levels by 2020.  In April 2015, the Governor of California issued an executive order establishing a new statewide GHG
reduction target of 40 percent below 1990 levels by 2030 to ensure California meets its 2050 GHG reduction target of 80 percent
below 1990 levels.  The CARB and the Province of Québec held their seventeenth joint allowance auction in November 2018 with 
current vintage auction allowances selling at a clearing price of $15.31 per metric ton and 2021 auction allowances selling at a
clearing price of $15.33 per metric ton.  The CARB expects allowance prices to be in the $15 to $30 range by 2020.  We have 
participated in quarterly auctions or in secondary markets, as appropriate, to secure allowances for our affected assets.

In July 2017, California enacted legislation extending its GHG cap-and-trade program through 2030 and the CARB adopted 
amendments to its cap-and-trade regulations that, among other things, established a framework for extending the program beyond 
2020 and linking the program to the new cap-and-trade program in Ontario, Canada beginning in January 2018.

Air Emissions

The Clean Air Act (CAA)

The CAA and comparable state laws and regulations relating to air emissions impose various responsibilities on owners and 
operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit fees, 
monitor emissions, submit reports and compliance certifications, and keep records.  The CAA requires that fossil-fueled electricity
generation plants meet certain pollutant emission standards and have sufficient emission allowances to cover sulfur dioxide (SO2) 
emissions and in some regions nitrogen oxide (NOX) emissions.

In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission reduction 
technologies.  These technologies include flue gas desulfurization (FGD) systems, dry sorbent injection (DSI), baghouses and 
activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective catalytic reduction 
(SCR) systems, low-NOX burners and/or overfire air systems on all units.  Additionally, our MISO coal-fueled facilities mainly
use low sulfur coal, which, prior to combustion, goes through a refined coal process to further reduce NOX and mercury emissions. 
In 2018, we received approval to use refined coal at some of our Texas coal-fueled facilities.

Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of 
SO2 and NOX emissions from our fossil-fueled generation units.  After certain EPA revisions to the rule the CSAPR became
effective January 1, 2015.  In October 2016, the EPA issued a CSAPR update, which revised the ozone season NOx limits for 22
eastern states, including Texas.  Under the CSAPR, our generating facilities in Illinois, Ohio, New Jersey, New York, Pennsylvania, 
Virginia,  and West Virginia  are  subject  to  cap-and-trade  programs  for  ozone-season  emissions  of  NOx  from  May  1  through
September 30 and for annual emissions for SO2 and NOX.  Our generating facilities in Texas are subject to the CSAPR NOx ozone 
season cap-and-trade program.  While we cannot predict the outcome of future proceedings related to the CSAPR, based upon our 
current operating plans, we do not believe that the CSAPR itself will cause any material operational, financial or compliance issues
to our business or require us to incur any material compliance costs.

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

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 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.  Second, certain electricity 
generation units built between 1962 and 1977 are subject to BART standards designed to improve visibility if such units cause or 
contribute to impairment of visibility in a federal class I area.  BART reductions of SO2 and NOX are required either on a unit-by-
unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CSAPR or other 
approved alternative program.

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

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

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

Affirmative Defenses During Malfunctions

In February 2013, the EPA proposed a rule requiring certain states to remove SIP exemptions for excess emissions during 
malfunctions or replace them with an affirmative defense.  In May 2015, the EPA finalized its 2013 proposal to extend the EPA's
proposed findings of inadequacy to states that have affirmative defense provisions, including Texas.  The final rule impacted 36
states, including Texas, Illinois and Ohio, in which we operate.  The EPA's final rule would require covered states to remove or 
replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during startup, shutdown and 
maintenance events.  Several states (including the State of Texas and the State of Ohio) and various industry parties (including 
Luminant) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court.
Before the oral argument was held, in April 2017, the D.C. Circuit Court granted the EPA's motion to continue oral argument and
ordered that the case be held in abeyance with the EPA to provide status reports to the D.C. Circuit Court on the EPA's review of 
the action at 90-day intervals.  In October 2018, the EPA partially granted Texas' petition for reconsideration of the Texas SIP call.  
We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation
of the rule as finalized could have a material impact on our results of operations, liquidity or financial condition.

National Ambient Air Quality Standards (NAAQS)

The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment.  The 
EPA has established NAAQS for six such pollutants, including SO2 and ozone.  Each state is responsible for developing a SIP that 
will attain and maintain the NAAQS.  These plans may result in the imposition of emission limits on our facilities.

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

Ozone Designations — The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per 
billion.  Various parties have filed lawsuits challenging the 2015 ozone NAAQS.  In November 2017, the EPA issued an initial 
round of area designations for the 2015 ozone NAAQS, designating most areas of the U.S. as attainment/unclassifiable.  Several 
states and other groups have filed lawsuits seeking to compel the EPA to complete designations for all areas of the country.  In
December 2017, the EPA notified states of expected nonattainment area designations for the 2015 ozone NAAQS.  Those areas
include areas concerning our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facility in Illinois and our Wise,
Ennis and Midlothian facilities in Texas.  In June 2018, the EPA finalized these designations as marginal nonattainment areas.

In November 2017, the EPA denied a petition from nine northeastern states to add several states, including Illinois and Ohio, 
to the Ozone Transport Region.  Eight of the northeastern states have filed a petition for judicial review challenging the EPA's
action in the D.C. Circuit Court.  Briefing in the D.C. Circuit Court was completed in October 2018, and oral argument was held
in November 2018.  Additionally, in January 2018, New York and Connecticut filed a lawsuit against the EPA in the Southern
District of New York seeking to compel the agency to issue a FIP for the 2008 ozone NAAQS that addresses sources in five upwind
states, including Illinois.  The plaintiffs filed a motion for summary judgment on the matter in April 2018, and the court granted 
that motion in June 2018.  As a result, the EPA was required to propose an action to address the 2008 ozone NAAQS by June 29,
2018, and promulgate a final action by December 6, 2018.  In January 2019, the plaintiffs informed the court that the EPA had 
satisfied its deadlines in accordance with the court's order.  However, in January 2019, New York, Connecticut, four other states
and the City of New York filed a separate petition for review in the D.C. Circuit Court challenging the final action the EPA took 
in December 2018 consistent with the Southern District of New York's order.

In November 2016, the State of Maryland petitioned the EPA to impose additional NOX emission control requirements on 
36  electricity  generation  units  in  five  upwind  states,  including  our  Zimmer  facility,  that  the  State  alleges  are  contributing  to 
nonattainment with the 2008 ozone NAAQS in Maryland.  In the fall of 2017, Maryland and several environmental groups filed 
lawsuits against the EPA seeking to compel the Agency to act on the State's petition.  In October 2018, the EPA took final action 
denying the Maryland petition.  While we cannot predict the outcome of the judicial proceedings, given that the Zimmer facility
utilizes SCR technology to control NOX emissions, we do not believe that the result of these proceedings could cause a material 
adverse impact on our future financial results.

Illinois Multi-Pollutant Standards (MPS)

In 2007, our MISO coal-fueled generation facilities elected to demonstrate compliance with the Illinois MPS, which require 
compliance with NOX, SO2 and mercury emissions limits.  We are in compliance with the MPS.  In October 2017, the Illinois 
Environmental Protection Agency (IEPA) filed a proposed rule with the Illinois Pollution Control Board (IPCB) that would amend 
the MPS rule by replacing the two separate group-wide annual emission rate limits that currently apply to our eight downstate
Illinois coal-fueled stations with tonnage limits for both SO2 (annual) and NOX (annual and seasonal) that apply to the eight stations
as a single group.  Under the MPS proposal, allowable annual emissions of SO2 and NOX would be 32 percent lower than under 
the current rule.  All other federal and state air quality regulations, including health-based standards, would remain unchanged 
and in place.  The proposed rule also would impose new requirements to ensure the continuous operation of existing SCR control
systems during the ozone season, require SCR-controlled units to meet an ozone season NOX emission rate limit, and set an
additional, site-specific annual SO2 limit for our Joppa Power Station.  We are supportive of the proposed rule as it would provide
operational flexibility to our MISO fleet while also providing a number of regulatory and environmental benefits.  IPCB held five 
hearings on the rule and we expect it to be finalized in 2019.

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New Source Review and CAA Matters

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

In August 2013, the U.S. Department of Justice (DOJ), acting as the attorneys for the EPA, filed a civil enforcement lawsuit 
against Luminant in federal district court in Dallas, alleging violations of the CAA, including its NSR standards, at our Big Brown
and  Martin  Lake  generation  facilities.   The  lawsuit  requests  (i)  the  maximum  civil  penalties  available  under  the  CAA  to  the 
government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and 
(ii) injunctive relief, including an order to apply for pre-construction permits which may require the installation of best available 
control technology at the affected units.  In August 2015, the district court granted Luminant's motion to dismiss seven of the nine 
claims asserted by the EPA in the lawsuit.

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

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

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

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

Coal Combustion Residuals (CCR)/Groundwater

The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at power 
generation facilities in dry form in landfills and in wet form in surface impoundments.  Each of our coal-fueled plants has at least 
one CCR surface impoundment.  At present, CCR is regulated by the states as solid waste.

13

Coal Combustion Residuals

The EPA's CCR rule, which took effect in October 2015, establishes minimum federal requirements for existing and new 
CCR landfills and surface impoundments, as well as inactive CCR surface impoundments.  The requirements include location 
restrictions, structural integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure
care, recordkeeping and notification.  The rule allows existing CCR surface impoundments to continue to operate for the remainder 
of  their  operating  life,  but  generally  would  require  closure  if  groundwater  monitoring  demonstrates  that  the  CCR  surface
impoundment is responsible for exceedances of groundwater quality protection standards or the CCR surface impoundment does
not meet location restrictions or structural integrity criteria.  The deadlines for beginning and completing closure vary depending
on several factors.  Several petitions for judicial review of the CCR rule were filed.  The Water Infrastructure Improvements for 
the Nation Act (the WIIN Act), which was enacted in December 2016, provides for EPA review and approval

ff

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

ff

t

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

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

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

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

14

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

a

Water

The  EPA  and  the  environmental  regulatory  bodies  of  states  in  which  we  operate  have  jurisdiction  over  the  diversion, 
impoundment and withdrawal of water for cooling and other purposes and the discharge of wastewater (including storm water)
from our facilities.  We believe our facilities are presently in material compliance with applicable federal and state requirements
relating to these activities.  We believe we hold all required permits relating to these activities for facilities in operation and have 
applied  for  or  obtained  necessary  permits  for  facilities  under  construction.   We  also  believe  we  can  satisfy  the  requirements 
necessary to obtain any required permits or renewals.

n

Cooling Water Intake Structures — Clean Water Act Section 316(b) regulations pertaining to existing water intake structures
at large generation facilities became effective in 2014.  This provision generally requires that the location, design, construction 
and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. 
Although the rule does not mandate a certain control technology, it does require site-specific assessments of technology feasibility
on a case-by-case basis at the state level.

At this time, we estimate the cost of our compliance with the cooling water intake structure rule will be approximately $16
million, with the majority of the expenditures in 2020 through 2023 at a group of our Illinois generation facilities.  Our estimate
could change materially depending upon a variety of factors, including site-specific determinations made by states in implementing
the rule, the results of impingement and entrainment studies required by the rule, the results of site-specific engineering studies
and the outcome of litigation concerning the rule.

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

The EPA issued a final rule in September 2017 postponing the earliest compliance dates in the ELG rule for bottom ash 

transport water and flue-gas desulfurization wastewater by two years, from November 1, 2018 to November 1, 2020.

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

Radioactive Waste

The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily using 
dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the U.S.  
Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear 
fuel storage capability is sufficient for the foreseeable future.

15

Environmental Capital Expenditures

Capital expenditures for our environmental projects totaled $13 million in the year ended December 31, 2018 and are expected 
to total approximately $35 million in the year ended December 31, 2019 for environmental control equipment to comply with 
regulatory requirements.

ERCOT
PJM
MISO
CAISO
Total

Year Ended December 31,

2018

Estimated 2019
6
$
14
14
1
35

$

9
3
1
—
13

$

$

16

Item 1A.  RISK FACTORS

Important factors, in addition to others specifically addressed in Item 7. Management's Discussion and Analysis of Financial 
Condition and Results of Operations, that could have a material adverse effect on our business, results of operations, liquidity and 
financial condition, or could cause results or outcomes to differ materially from those contained in or implied by any forward-
looking statement in this Annual Report, are described below.  There may be further risks and uncertainties that are not currently
known or that are not currently believed to be material that may adversely affect our business, results of operations, liquidity,tt
financial condition and prospects and the market price of our common stock in the future.  The realization of any of these factors 
could cause investors in our common stock to lose all or a substantial portion of their investment.

Market, Financial and Economic Risks

,

Our revenues, results of operations and operating cash flows generally may be impacted by price fluctuations in the wholesale 
power market and other market factors beyond our control.

We are not guaranteed any rate of return on capital investments in our businesses.  We conduct integrated power generation
and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales of electricity 
and services to end users and commodity risk management.  Our wholesale and retail businesses are to some extent countercyclical 
in nature, particularly for the wholesale power and ancillary services supplied to the retail business.  However, we do have a 
wholesale power position that exceeds the overall load requirements of our retail business and is subject to wholesale power price 
moves.  As a result, our revenues, results of operations and operating cash flows depend in large part upon wholesale market prices 
for electricity, natural gas, uranium, lignite, coal, fuel and transportation in our regional markets and other competitive markets
and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities.
Market prices for power, capacity, ancillary services, natural gas, coal and oil are unpredictable and may fluctuate substantially 
over relatively short periods of time.  Unlike most other commodities, electric power can only be stored on a very limited basis
and generally must be produced concurrently with its use.  As a result, power prices are subject to significant volatility due to 
supply and demand imbalances, especially in the day-ahead and spot markets.  Demand for electricity can fluctuate dramatically,
creating periods of substantial under- or over-supply.  Over-supply can also occur as a result of the construction of new power
plants, as we have observed in recent years.  During periods of over-supply, electricity prices might be depressed.  Also, at times
there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity 
and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in
these markets.

rr

The majority of our facilities operate as "merchant" facilities without long-term power sales agreements.  As a result, we
largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and retail 
power markets on a short-term basis and are not guaranteed any rate of return on our capital investments.  Consequently, there
can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those facilities
at commercially attractive rates or that our facilities will be able to operate profitably.  We depend, in large part, upon prevailing 
market prices for power, capacity and fuel.  Given the volatility of commodity power prices, to the extent we do not secure long-
term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to
volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.

d

ff

We purchase natural gas, coal, oil and nuclear fuel for our generation facilities, and higher than expected fuel costs or volatility 
in these fuel markets may have an adverse impact on our costs, revenues, results of operations, financial condition and cash
flows.

tt

We rely on natural gas, coal and oil to fuel the majority of our power generation facilities.  Delivery of these fuels to the 
facilities  is  dependent  upon  the  continuing  financial  viability  of  contractual  counterparties  as  well  as  upon  the  infrastructure
(including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve each generation 
facility.  As a result, we are subject to the risks of disruptions or curtailments in the production of power at our generation facilities 
if no fuel is available at any price or if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.

n

ff

17

We have sold forward a substantial portion of our expected power sales in the next one to two years in order to lock in long-
term prices.  In order to hedge our obligations under these forward power sales contracts, we have entered into long-term and 
short-term contracts for the purchase and delivery of fuel.  Many of the forward power sales contracts do not allow us to pass
through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure
events or the default of a fuel supplier or transporter.  Fuel costs (including diesel, natural gas, lignite, coal and nuclear fuel) may
be volatile, and the wholesale price for electricity may not change at the same rate as changes in fuel costs, and disruptions in our 
fuel supplies may therefore require us to find alternative fuel sources at higher costs, to find other sources of power to deliver to 
counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted.  In addition, we 
purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in
meeting obligations.  Further, any changes in the costs of coal, fuel oil, natural gas or transportation rates and changes in the 
relationship between such costs and the market prices of power will affect our financial results.  If we are unable to procure fuel 
for physical delivery at prices we consider favorable, our financial condition, results of operations and cash flows could be materially 
adversely affected.

t

We also buy significant quantities of fuel on a short-term or spot market basis.  Prices for all of our fuels fluctuate, sometimes
rising or falling significantly over a relatively short period of time.  The price we can obtain for the sale of energy may not rise at 
the same rate, or may not rise at all, to match a rise in fuel or delivery costs.  This may have a material adverse effect on our 
financial performance.  Volatility in market prices for fuel and electricity may result from, among other factors:

t

• 
• 
• 
• 
• 
• 
• 
• 
• 
• 
• 

• 

• 
• 

• 
• 
• 

• 
• 
• 
• 
• 

demand for energy commodities and general economic conditions;
volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;
volatility in market heat rates;
volatility in coal and rail transportation prices;
volatility in nuclear fuel and related enrichment and conversion services;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
severe or unexpected weather conditions, including drought and limitations on access to water;
seasonality;
changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;
illiquidity in the wholesale electricity or other commodity markets;
transmission  or  transportation  disruptions,  constraints,  inoperability  or  inefficiencies,  or  other  changes  in  power 
transmission infrastructure;
development and availability of new fuels, new technologies and new forms of competition for the production and 
storage of power, including competitively priced alternative energy sources or storage;
changes in market structure and liquidity;
changes  in  the  way  we  operate  our  facilities,  including  curtailed  operation  due  to  market  pricing,  environmental 
regulations and legislation, safety or other factors;
changes in generation capacity or efficiency;
outages or otherwise reduced output from our generation facilities or those of our competitors;
changes in electric capacity, including the addition of new supplies of power as a result of the development of new
plants, expansion of existing plants, the continued operation of uneconomic power plants due to federal, state or local
subsidies, or additional transmission capacity;
our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
changes in the credit risk or payment practices of market participants;
changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;
natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and
changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and 
legislation.

We may be forced to retire or idle underperforming generation units, which could result in significant costs and have an adverse 
effect on our operating results.

During 2018, we retired our Monticello, Sandow 4, Sandow 5, Big Brown, Killen, Stuart and Northeastern units.  A sustained 
decrease in the financial results from, or the value of, our generation units ultimately could result in the retirement or idling of 
certain other generation units.  In recent years, we have operated certain of our lignite- and coal-fueled generation assets only
during parts of the year that have higher electricity demand and, therefore, higher related wholesale electricity prices.

18

Our  assets  or  positions  cannot  be  fully  hedged  against  changes  in  commodity  prices  and  market  heat  rates,  and  hedging 
transactions may not work as planned or hedge counterparties may default on their obligations.

Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notably
electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative
to the duration of available markets for various hedging activities.  Generally, commodity markets that we participate in to hedge 
our exposure to electricity prices and heat rates have limited liquidity after two to three years.  Further, our ability to hedge our 
revenues by utilizing cross-commodity hedging strategies with natural gas hedging instruments is generally limited to a duration 
of four to five years.  To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can
materially impact our results of operations, cash flows, liquidity and financial condition, either favorably or unfavorably.

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions 
of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium and refined 
products, and other commodities, within established risk management guidelines.  As part of this strategy, we routinely utilize
fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter 
markets or on exchanges.  Although we devote a considerable amount of time and effort to the establishment of risk management 
procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always 
function as planned and cannot eliminate all the risks associated with these activities.  For example, we hedge the expected needs
of  our  wholesale  and  retail  customers,  but  unexpected  changes  due  to  weather,  natural  disasters,  consumer  behavior,  market 
constraints or other factors could cause us to purchase electricity to meet unexpected demand in periods of high wholesale market 
prices or resell excess electricity into the wholesale market in periods of low prices.  As a result of these and other factors, risk 
management decisions may have a material adverse effect on us.

ff

Based on economic and other considerations, we may not be able to, or we may decide not to, hedge the entire exposure of 
our operations from commodity price risk.  To the extent we do not hedge against commodity price risk and applicable commodity 
prices change in ways adverse to us, we could be materially and adversely affected.  To the extent we do hedge against commoditytt
price risk, those hedges may ultimately prove to be ineffective.

With the tightening of credit markets that began in 2008 and the expansion of regulatory oversight through various financial 
reforms, there has been a decline in the number of market participants in the wholesale energy commodities markets, resulting in 
less liquidity.  Notably, participation by financial institutions and other intermediaries (including investment banks) in such markets 
has declined.  Extended declines in market liquidity could adversely affect our ability to hedge our financial exposure to desired 
levels.

h

To the extent we engage in hedging and risk management activities, we are exposed to the credit risk that counterparties that 
owe us money, energy or other commodities as a result of these activities will not perform their obligations to us.  Should the
counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor 
the underlying commitment at then-current market prices.  Additionally, our counterparties may seek bankruptcy protection under
Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code.  Our credit risk may be exacerbated to the extent collateral 
held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us.  There can be no assurance
that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our
financial condition, results of operations and cash flows.  In such event, we could incur losses or forgo expected gains in addition
to amounts, if any, already paid to the counterparties.  Market participants in the RTOs and ISOs in which we operate are also 
exposed to risks that another market participant may default on its obligations to pay such RTO or ISO for electricity or services
taken, in which case such costs, to the extent not offset by posted security and other protections available to such RTO or ISO,
may be allocated to various non-defaulting RTO or ISO market participants, including us.

19

We  do  not  apply  hedge  accounting  to  our  commodity  derivative  transactions,  which  may  cause  increased  volatility  in  our 
quarterly and annual financial results.

We engage in economic hedging activities to manage our exposure related to commodity price fluctuations through the use 
of financial and physical derivative contracts for commodities.  These derivatives are accounted for in accordance with GAAP, 
which requires that we record all derivatives on the balance sheet at fair value with changes in fair value immediately recognized 
in earnings as unrealized gains or losses.  GAAP permits an entity to designate qualifying derivative contracts as normal purchases
and sales.  If designated, those contracts are not recorded at fair value.  GAAP also permits an entity to designate qualifying
derivative contracts in a hedge accounting relationship.  If a hedge accounting relationship is used, a significant portion of the 
changes in fair value is not immediately recognized in earnings.  We have chosen not to apply hedge accounting to our commodity
contracts and we have chosen to elect normal purchase normal sales in only limited cases, such as our retail sales contracts.  As
a result, our quarterly and annual financial results in accordance with GAAP are subject to significant fluctuations caused by 
changes in forward commodity prices.

Competition, change in market structure, and/or state or federal interference in the wholesale and retail power markets, together 
with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our generation and competitive retail businesses rely on a competitive wholesale marketplace.  The competitive wholesale 
marketplace may be undermined by changes in market structure and out-of-market subsidies provided by federal or state entities,
including bailouts of uneconomic plants, imports of power from Canada, renewable mandates or subsidies, as well as out-of-
market payments to new generators.  

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of 
regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary
services, as well as in the procurement of fuel, transmission and transportation services.  Moreover, aggregate demand for power 
may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by 
alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat 
and solid waste sources.  Regulatory initiatives designed to enhance and/or subsidize renewable generation increases competition 
from these types of facilities and out-of-market subsidies to existing or new generation can undermine the competitive wholesale
marketplace, which can lead to premature retirement of existing facilities, including those owned by us.

We also compete against other energy merchants on the basis of our relative operating skills, financial position and access
to credit sources.  Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit 
support such as letters of credit and other assurances that their energy contracts will be satisfied.  Companies with which we
compete may have greater resources or experience in these areas.  Over time, some of our plants may become unable to compete 
because of subsidized generation, including public utility commission supported power purchase agreements, and the construction
of new plants.  Such new plants could have a number of advantages including: more efficient equipment, newer technology that 
could result in fewer emissions or more advantageous locations on the electric transmission system.  Additionally, these competitors 
may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or
the additional resources derived from owning more efficient facilities.

Other factors may contribute to increased competition in wholesale power markets.  New forms of capital and competitors 
have entered the industry, including financial investors who perceive that asset values are at levels below their true replacement 
value.  As a result, a number of generation facilities in the U.S. are now owned by lenders and investment companies.  Furthermore,
mergers and asset reallocations in the industry could create powerful new competitors.  Under any scenario, we anticipate that we
will face competition from numerous companies in the industry.  Certain federal and state entities in jurisdictions in which we
operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic plants and attempt to
incent the development of new renewable resources as well as increase energy efficiency investments.  Continued subsidies (or 
increases thereto) to our competitors could have a material adverse effect on our financial condition, results of operations and cash
flows.

20

In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins
that we can earn on the volumes we are able to serve.  Further, with retail competition, it is easier for residential customers where
we serve load to switch to and from competitive electricity generation suppliers for their energy needs.  The volatility and uncertainty
that results from such mobility may have material adverse effects on our financial condition, results of operations and cash flows. 
For example, if fewer customers switch to another supplier than anticipated, the load we must serve will be greater than anticipated 
and, if market prices of fuel have increased, our costs will increase more than expected due to the need to go to the market to cover 
the incremental supply obligation.  If more customers switch to another supplier than anticipated, the load we must serve will be 
lower than anticipated and, if market prices of electricity have decreased, our operating results could suffer.

Our results of operations and financial condition could be materially and adversely affected if energy market participants
continue to construct additional generation facilities (i.e., new-build) or expand or enhance existing generation facilities despite
relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices.

Given  the  overall  attractiveness  of  certain  of  the  markets  in  which  we  operate  and  certain  tax  benefits  associated  with 
renewable energy, among other matters, energy market participants have continued to construct new generation facilities (i.e., 
new-build) or invest in enhancements or expansions of existing generation facilities despite relatively low wholesale power prices. 
If this market dynamic continues, our results of operations and financial condition could be materially and adversely affected if 
such additional generation capacity results in an over-supply of electricity that causes a reduction in wholesale power prices.

Unauthorized hedging and related activities by our employees could result in significant losses.

We  have  various  internal  policies,  processes,  and  controls  designed  to  monitor  hedging  activities  and  positions.   These
policies, processes, and controls are designed, in part, to prevent unauthorized purchases or sales of products by our employees
or alert our risk management teams of any trades that have not been entered into our risk management systems.  We cannot assure, 
however, that these steps will detect and prevent inaccurate reporting and all potential violations of our risk management policies,
processes, and controls, particularly if deception or other intentional misconduct is involved.  A significant policy violation that 
is not detected could result in a substantial financial loss.

n

Our risk management policies cannot fully eliminate the risk associated with our commodity hedging activities.

Our operations and other commodity hedging activities expose us to risks of commodity price movements.  We attempt to
manage this exposure by entering into commodity hedging transactions and establishing risk management policies and procedures.
These risk management procedures may not work as planned and cannot eliminate all risks associated with these activities.  As a
result, we cannot fully predict the impact that our commodity hedging activities and risk management decisions may have on our 
business and/or financial condition, results of operations and cash flows.

Economic downturns would likely have a material adverse effect on our businesses.

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low
levels  in  the  market  prices  for  power,  generation  capacity  and  natural  gas,  which  can  fluctuate  substantially.    Increased 
unemployment of residential customers and decreased demand for products and services by commercial and industrial customers
resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible
customer balances, which would negatively impact our overall sales and cash flows.  Additionally, prolonged economic downturns 
that negatively impact our financial condition, results of operations and cash flows could result in future material impairment
charges to write down the carrying value of certain assets to their respective fair values.

Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during 
times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in the
future, which could have a material adverse effect on us.  We currently maintain non-investment grade credit ratings that could
negatively affect our ability to access capital on favorable terms or result in higher collateral requirements, particularly if our 
credit ratings were to be downgraded in the future.

f

Our businesses are capital intensive.  In general, we rely on access to financial markets and credit facilities as a significant 
source of liquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows.  The
inability to raise capital or to access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our 
ability to meet our obligations or sustain and grow our businesses and could increase capital costs and collateral requirements, 
any of which could have a material adverse effect on us.

tt

21

Our access to capital and the cost and other terms of acquiring capital are dependent upon, and could be adversely impacted 

by, various factors, including:

• 

• 
• 
• 
• 
• 
• 
• 

• 
• 
• 
• 
• 
• 
• 
• 

general economic and capital markets conditions, including changes in financial markets that reduce available liquidity
or the ability to obtain or renew credit facilities on favorable terms or at all;
conditions and economic weakness in the U.S. power markets;
regulatory developments;
changes in interest rates;
a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;
a reduction in Vistra Energy's or its applicable subsidiaries' credit ratings;
our level of indebtedness and compliance with covenants in our debt agreements;
a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities
that affects the ability of such lender(s) to make loans to us;
security or collateral requirements;
general credit availability from banks or other lenders for us and our industry peers;
investor confidence in the industry and in us and the wholesale electricity markets in which we operate;
volatility in commodity prices that increases credit requirements;
a material breakdown in our risk management procedures;
the occurrence of changes in our businesses;
disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities, and
changes in or the operation of provisions of tax and regulatory laws.

In addition, we currently maintain non-investment grade credit ratings.  As a result, we may not be able to access capital on 
terms (financial or otherwise) as favorable as companies that maintain investment-grade credit ratings or we may be unable to 
access capital at all at times when the credit markets tighten.  In addition, our non-investment grade credit ratings may result in 
counterparties requesting collateral support (including cash or letters of credit) in order to enter into transactions with us.

A downgrade in long-term debt ratings generally causes borrowing costs to increase and the potential pool of investors to 
shrink and could trigger liquidity demands pursuant to contractual arrangements.  Future transactions by Vistra Energy or any of 
its subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit ratings.

Our indebtedness could adversely affect our ability in the future to raise additional capital to fund our operations.  It could
also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy, or our industry, r
as well as impact our cash available for distribution.

In connection with the Merger, we assumed all of Dynegy's outstanding indebtedness.  As of December 31, 2018, we had 
approximately $11.1 billion of total indebtedness and approximately $10.4 billion of indebtedness net of cash.  Our debt could 
have negative consequences for our financial condition including:

• 
• 

• 
• 
• 

• 
• 

• 

• 

increasing our vulnerability to general economic and industry conditions;
requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and 
interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our common stock or to 
fund our operations, capital expenditures and future business opportunities;
limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
limiting our ability to fund operations or future acquisitions;
restricting our ability to make distributions or pay dividends with respect to our capital stock and the ability of our 
subsidiaries to make distributions to us, in light of restricted payment and other financial covenants in our credit 
facilities and other financing agreements;
inhibiting the growth of our stock price;
exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under the
Vistra Operations Credit Facilities, are at variable rates of interest;
limiting our ability to obtain additional financing for working capital including collateral postings, capital 
expenditures, debt service requirements, acquisitions and general corporate or other purposes, and
limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to
our competitors who may have less debt.

22

We may not be successful in obtaining additional capital for these or other reasons.  Furthermore, we may be unable to refinance
or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof.  Our failure to obtain 
additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing
indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The Vistra Operations Credit Facilities impose restrictions on us and any failure to comply with these restrictions could have 
a material adverse effect on us.

The Vistra Operations Credit Facilities contain restrictions that could adversely affect us by limiting our ability to plan for, 
or react to, market conditions or to meet our capital needs and could result in an event of default under the Vistra Operations Credit 
Facilities.  The Vistra Operations Credit Facilities contain events of default customary for financings of this type.  If we fail to
comply with the covenants in the Vistra Operations Credit Facilities and are unable to obtain a waiver or amendment, or a default 
exists and is continuing, the lenders under such agreements could give notice and declare outstanding borrowings thereunder 
immediately due and payable.  Any such acceleration of outstanding borrowings could have a material adverse effect on us.

Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs.  If we are unable to 
provide such security, it may restrict our ability to conduct our business, which could have a material adverse effect on us.

We  undertake  certain  hedging  and  commodity  activities  and  enter  into  certain  financing  arrangements  with  various 
counterparties that require cash collateral or the posting of letters of credit which are at risk of being drawn down in the event we
default on our obligations.  We currently use margin deposits, prepayments and letters of credit as credit support for commodity tt
procurement  and  risk  management  activities.    Future  cash  collateral  requirements  may  increase  based  on  the  extent  of  our 
involvement in standard contracts and movements in commodity prices, and also based on our credit ratings and the general
perception of creditworthiness in the markets in which we operate.  In the case of commodity arrangements, the amount of such 
credit support that must be provided typically is based on the difference between the price of the commodity in a given contract 
and the market price of the commodity.  Significant movements in market prices can result in our being required to provide cash
collateral and letters of credit in very large amounts.  The effectiveness of our strategy may be dependent on the amount of collateral
available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to 
meet.  Without a sufficient amount of working capital to post as collateral, we may not be able to manage price volatility effectively 
or to implement our strategy.  An increase in the amount of letters of credit or cash collateral required to be provided to our
counterparties may have a material adverse effect on us.

We may be unable to successfully integrate the operations of the legacy Dynegy assets with our existing operations or to realize
targeted cost savings, revenues and other anticipated benefits of the Merger.

The success of the Merger will depend, in part, on our ability to realize the anticipated benefits and synergies from integrating 
Dynegy's assets with our existing retail and generation business.  To realize these anticipated benefits, the businesses must be
successfully combined.

We may be required to make unanticipated capital expenditures or investments in order to maintain, integrate, improve or 
sustain the assets' operations, or take unexpected write-offs or impairment charges resulting from the Merger.  Further, we may
be subject to unanticipated or unknown liabilities relating to the legacy Dynegy assets and operations.  If any of these factors occur 
or limit our ability to integrate the businesses successfully or on a timely basis, the expectations regarding our future financial 
condition and results of operations following the Merger might not be met.

In addition, we continue to evaluate our estimates of synergies to be realized from, and refine the fair value accounting 
allocations associated with, the Merger.  Accordingly, actual cost-savings, the costs required to realize the cost-savings, and the 
source of the cost-savings could differ materially from our estimates, and we cannot ensure that we will achieve the full amount nn
of cost-savings on the schedule anticipated or at all.

d

Finally, we may not be able to achieve the targeted operating or long-term strategic benefits of the Merger.  If the combined 
businesses are not able to achieve our objectives, or are not able to achieve our objectives on a timely basis, the anticipated benefits 
of the Merger may not be realized fully or at all.  An inability to realize the full extent of, or any of, the anticipated benefits of the 
Merger, as well as any delays encountered in the integration process, could have an adverse effect on our financial condition, 
results of operations and cash flows.

d

23

The allocation of the purchase price to the value amounts recognized for the assets acquired and liabilities assumed related to
the Merger as of the Merger Date is preliminary in nature and could differ materially from our initial purchase price allocation.

Based on the opening price of our common stock on the Merger Date, the preliminary purchase price of Dynegy in the Merger 
was approximately $2.3 billion as of December 31, 2018.  The purchase price allocation is substantially complete, but is dependent 
upon final valuation determinations, which may materially change from our current estimates.  The preliminary purchase price
allocation reflected in our consolidated financial statements represents our current best estimates for property plant and equipment, 
identifiable intangible assets and liabilities, goodwill, inventories, asset retirement obligations, contingent liabilities and deferred 
taxes.  We currently expect the final purchase price allocation will be completed no later than the first quarter of 2019 and goodwill 
will be allocated to the related reporting units at that time.

d

The proposed acquisition of Crius may not be completed in a timely fashion or at all, and the failure to successfully integrate
the Crius business and operations in the expected time frame may adversely affect our future results.

Completion of the Crius Acquisition is subject to satisfaction of a number of conditions, including the receipt of unitholder 
approval and certain regulatory approvals for which the timing cannot be predicted.  The expiration or termination of the applicable 
waiting periods, and any extension of the waiting periods, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as 
amended, and approval by the FERC regulations may take considerable time.  If Vistra Energy is not able to successfully integrate
Crius' business and operations, or if there are additional and unforeseen expenses or delays in combining the businesses, realizing 
any  anticipated  synergies,  accelerating  retail  growth  expansion  or  optimizing  existing  fleet  and  operational  efficiencies,  the 
anticipated benefits of the Crius Acquisition may not be realized fully or at all or may take longer to realize than expected.

We may not be able to complete future acquisitions or successfully integrate future acquisitions into our business, which could
result in unanticipated expenses and losses.

As part of our growth strategy, including our desire to grow our retail platform, we may pursue acquisitions of assets or 
operating entities.  Our ability to continue to implement this component of our growth strategy will be limited by our ability to
identify appropriate acquisition or joint venture candidates and our financial resources, including available cash and access to
capital.  Any expense incurred in completing acquisitions or entering into joint ventures, the time it takes to integrate an acquisition
or our failure to integrate acquired businesses successfully could result in unanticipated expenses and losses.  Furthermore, we 
may not be able to fully realize the anticipated benefits from any future acquisitions or joint ventures we may pursue.  In addition, 
the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and
expenses and may require significant financial resources that would otherwise be available for the execution of our business 
strategy.

Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition.

In evaluating our business and the strategic fit of our various assets, we may determine to sell one or more of such assets. 
Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an acceptable
price and on acceptable terms and in a timely manner.  In addition, a prospective buyer may have difficulty obtaining financing. 
Divestitures could involve additional risks, including:

difficulties in the separation of operations and personnel;
the need to provide significant ongoing post-closing transition support to a buyer;

• 
• 
•  management's attention may be temporarily diverted;
• 
• 
• 
• 

the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;
the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;
the disruption of our business, and
potential loss of key employees.

We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset,

which could adversely affect our results of operations and financial condition.

24

If our goodwill, intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to
earnings.

ii

We have significant goodwill, intangible assets and long-lived assets recorded on our balance sheet.  In accordance with U.S.
GAAP, goodwill and non-amortizing intangible assets are required to be tested for impairment at least annually.  Additionally, we
review goodwill, our intangible assets and long-lived assets for impairment when events or changes in circumstances indicate the
carrying value of the asset may not be recoverable.  Factors that may be considered include a decline in future cash flows, slower 
growth rates in the energy industry, and a sustained decrease in the price of our common stock.

We performed our annual assessment of goodwill and non-amortizing intangibles and determined that no impairment was 
required.  However, impairment assessments will be performed in future periods and may result in an impairment loss, which 
could be material.

Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in an
ownership change as defined in Internal Revenue Code (IRC) §382 could further limit our ability to use our federal net operating 
losses or alternative minimum tax credits to offset our future taxable income.

If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs and AMT credits
that could be used in any one year following such ownership change could be substantially limited.  In general, an "ownership
change" would occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, 
each of which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock.  Given IRC §382's broad 
definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is 
outside our control.  Vistra Energy acquired NOLs and AMT credits from its merger with Dynegy, however, Vistra Energy's use
of such attributes is limited under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy.  If 
there  is  an  "ownership  change"  with  respect  to  Vistra  Energy  (including  by  the  normal  trading  activity  of  greater  than  5%
shareholders), the utilization of all NOLs and AMT credits existing at that time would be subject to additional annual limitations
based upon a formula provided under IRC §382 that is based on the fair market value of the Company and prevailing interest rates
at the time of the ownership change.

Recent U.S. tax legislation may materially adversely affect Vistra Energy's financial condition, results of operations and cash
flows.

On December 22, 2017, President Trump signed into law a comprehensive tax reform bill (the TCJA), that significantly 
reforms the Internal Revenue Code.  The TCJA, among other things, contains significant changes to corporate taxation, including
a reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense, limitation of the
deduction for certain net operating losses to 80% of current year taxable income, an indefinite net operating loss carryforward, 
immediate deductions for certain new investments instead of deductions for depreciation expense over time and the modification 
or repeal of many business deductions and credits.  While we expect a beneficial impact from the TCJA from the reduction in 
corporate tax rates and immediate deductions for certain new investments, we continue to examine the tax reform legislation, as
its overall impact is uncertain, and note that certain provisions of the TCJA or its interaction with existing law could adversely
affect the Company's business and financial condition.  The impact of this tax reform legislation on our stockholders is also 
uncertain and could be adverse.

We may be responsible for U.S. federal and state income tax liabilities that relate to the PrefCo Preferred Stock Sale and Spin-
Off.

Pursuant to the Tax Matters Agreement, the parties thereto 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 covenant results in additional taxes to the other parties.  If we breach such a covenant (or, in certain circumstances, if our 
stockholders or creditors of our Predecessor take or took certain actions that result in the intended tax treatment of the Spin-Off 
not to be preserved), we may be required to make substantial indemnification payments to the other parties to the Tax Matters 
Agreement.

f

The Tax Matters Agreement also allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp.
and us.  For periods prior to the Spin-Off, (i) Vistra Energy is generally required to reimburse EFH Corp. with respect to any taxes
paid by EFH Corp. that are attributable to us and (ii) EFH Corp. is generally required to reimburse us with respect to any taxes
paid by us that are attributable to EFH Corp.

25

We are also required to indemnify EFH Corp. against certain taxes in the event 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.

Our indemnification obligations to EFH Corp. are not limited by any maximum amount.  If we are required to indemnify
EFH Corp. or such other persons under the circumstances set forth in the Tax Matters Agreement, we may be subject to substantial 
liabilities.

We are required to pay the holders of TRA Rights for certain tax benefits, which amounts are expected to be substantial.

On the Effective Date, we entered into the TRA with American Stock Transfer & Trust Company, LLC, as the transfer agent. 
Pursuant to the TRA, we issued beneficial interests in the rights to receive payments under the TRA (TRA Rights) to the first lien 
creditors of our Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to receive
such TRA Rights under the Plan of Reorganization.  Our financial statements reflect a liability of $420 million as of December 31, 
2018 related to these future payment obligations (see Note 10 to the Financial Statements).  This amount is based on certain 
assumptions as described more fully in the notes to the financial statements and the actual payments made under the TRA could 
be materially different than this estimate.

The TRA provides for the payment by us to the holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S.
federal, state and local income tax that we and our subsidiaries actually realize as a result of our use of (a) the tax basis step up 
attributable to the PrefCo Preferred Stock Sale, (b) the entire tax basis of the assets acquired as a result of the purchase and sale
agreement, dated as of November 25, 2015 by and between La Frontera Ventures, LLC and Luminant, and (c) tax benefits related 
to imputed interest deemed to be paid by us as a result of payments under the TRA.  The amount and timing of any payments
under the TRA will vary depending upon a number of factors, including the amount and timing of the taxable income we generate 
in the future and the tax rate then applicable, our use of loss carryovers and the portion of our payments under the TRA constituting
imputed interest.

Although we are not aware of any issue that would cause the IRS to challenge the tax benefits that are the subject of the 
TRA, recipients of the payments under the TRA will not be required to reimburse us for any payments previously made if such 
tax benefits are subsequently disallowed.  As a result, in such circumstances, Vistra Energy could make payments under the TRA 
that are greater than its actual cash tax savings.  Any amount of excess payment can be used to reduce future TRA payments, but
cannot be immediately recouped, which could adversely affect our liquidity.

Because Vistra Energy is a holding company with no operations of its own, its ability to make payments under the TRA is
dependent on the ability of its subsidiaries to make distributions to it.  To the extent that Vistra Energy is unable to make payments 
under the TRA because of the inability of its subsidiaries to make distributions to us for any reason, such payments will be deferred 
and will accrue interest until paid, which could adversely affect our results of operations and could also affect our liquidity iny
periods in which such payments are made.

The payments we will be required to make under the TRA could be substantial.

We may be required to make an early termination payment to the holders of TRA Rights under the TRA.

The TRA provides that, in the event that Vistra Energy breaches any of its material obligations under the TRA, or upon 
certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under 
the TRA may treat such event as an early termination of the TRA, in which case Vistra Energy would be required to make an 
immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100 basis
points) of the anticipated future tax benefits based on certain valuation assumptions.

As a result, upon any such breach or change of control, we could be required to make a lump sum payment under the TRA 
before we realize any actual cash tax savings and such lump sum payment could be greater than our future actual cash tax savings.

The aggregate amount of these accelerated payments could be materially more than our estimated liability for payments 
made under the TRA set forth in our financial statements.  Based on this estimation, our obligations under the TRA could have a
substantial negative impact on our liquidity.

26

We are potentially liable for U.S. income taxes of the entire EFH Corp. consolidated group for all taxable years in which we 
were a member of such group.

Prior to the Spin-Off, EFH Corporate Services Company, EFH Properties Company and certain other subsidiary corporations 
were  included  in  the  consolidated  U.S.  federal  income  tax  group  of  which  EFH  Corp.  was  the  common  parent  (EFH  Corp.
Consolidated Group).  In addition, pursuant to the private letter ruling from the IRS that we received in connection with the Spin-
Off, Vistra Energy will be considered a member of the EFH Corp. Consolidated Group immediately prior to the Spin-Off.  Under 
U.S. federal income tax laws, any corporation that is a member of a consolidated group at any time during a taxable year is severally 
liable for the group's entire federal income tax liability for the entire taxable year.  In addition, entities that are disregarded for 
U.S. federal income tax purposes may be liable as successors under common law theories or under certain regulations to the extent 
corporations transferred assets to such entities or merged or otherwise consolidated into such entities, whether under state law or 
purely as a matter of federal income tax law.  Thus, notwithstanding any contractual rights to be reimbursed or indemnified by
EFH Corp. pursuant to the Tax Matters Agreement, to the extent EFH Corp. or other members of the EFH Corp. Consolidated 
Group fail to make any U.S. federal income tax payments required of them by law in respect of taxable years for which the
Company or any subsidiary noted above was a member of the EFH Corp. Consolidated Group, the Company or such subsidiary
may be liable for the shortfall.  At such time, we may not have sufficient cash on hand to satisfy such payment obligation.

a

aa

Our ability to claim a portion of depreciation deductions may be limited for a period of time.

Under the Internal Revenue Code of 1986, as amended, 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 for the Company 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 certainrr
tax attributes existing at the time of any such ownership change and have an impact on our tax liabilities and on our obligations
under the TRA.

ff

Regulatory and Legislative Risks

y

g

g

Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the
future impact, our businesses, results of operations, liquidity and financial condition.

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory 
initiatives regarding the restructuring of the energy industry, including competition in power generation and sale of electricity. 
Although we attempt to comply with changing legislative and regulatory requirements, there is a risk that we will fail to adapt to 
any such changes successfully or on a timely basis.

t

Our businesses are subject to numerous state and federal laws (including PURA, the Federal Power Act, the Atomic Energy 
Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act (CAA), the Energy Policy Act of 2005 and the Dodd-
Frank Wall Street Reform and Consumer Protection Act), changing governmental policy and regulatory actions (including those 
of the FERC, the NERC, the RCT, the MSHA, the EPA, the NRC, CFTC, state public utility commissions and state environmental
regulatory agencies), and the rules, guidelines and protocols of ERCOT, CAISO, ISO-NE, MISO, NYISO and PJM with respect 
to various matters, including, but not limited to, market structure and design, operation of nuclear generation facilities, construction
and  operation  of  other  generation  facilities,  development,  operation  and  reclamation  of  lignite  mines,  recovery  of  costs  and 
investments,  decommissioning  costs,  market  behavior  rules,  present  or  prospective  wholesale  and  retail  competition  and 
environmental matters.  We, along with other market participants, are subject to electricity pricing constraints and market behavior 
and other competition-related rules and regulations under PURA.  Changes in, revisions to, or reinterpretations of, existing lawsaa
and regulations may have a material adverse effect on us.

Dynegy's legacy business operates in a number of states and markets outside of our historical operations.  As a result of the 
Merger, we became subject to the regulatory requirements of such markets, including CAISO, ISO-NE, MISO, NYISO and PJM.  
Because we have historically not been subject to the regulations of such markets, we may incur additional expenses, which may 
be material, to learn such regulations and ensure that we are operating in compliance with such regulations.

27

We are required to obtain, and to comply with, government permits and approvals.

We are required to obtain, and to comply with, numerous permits and licenses from federal, state and local governmental 
agencies.  The process of obtaining and renewing necessary permits and licenses can be lengthy and complex and can sometimes
result in the establishment of conditions that make the project or activity for which the permit or license was sought unprofitable 
or otherwise unattractive.  In addition, such permits or licenses may be subject to denial, revocation or modification under various 
circumstances.  Failure to obtain or comply with the conditions of permits or licenses, or failure to comply with applicable lawsaa
or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our 
delivery of electricity to our customers and may subject us to penalties and other sanctions.  Although various regulators routinely 
renew existing permits and licenses, renewal of our existing permits or licenses could be denied or jeopardized by various factors, 
including (a) failure to provide adequate financial assurance for closure, (b) failure to comply with environmental, health and
safety laws and regulations or permit conditions, (c) local community, political or other opposition and (d) executive, legislative
or regulatory action.

aa

Our inability to procure and comply with the permits and licenses required for our operations, or the cost to us of such 
procurement or compliance, could have a material adverse effect on us.  In addition, new environmental legislation or regulations,
if enacted, or changed interpretations of existing laws, may cause routine maintenance activities at our facilities to need to be 
changed to avoid violating applicable laws and regulations or elicit claims that historical routine maintenance activities at our 
facilities violated applicable laws and regulations.  In addition to the possible imposition of fines in the case of any such violations,
we may be required to undertake significant capital investments in emissions control technology and obtain additional operating
permits or licenses, which could have a material adverse effect on us.

Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.

We are subject to extensive environmental regulation by governmental authorities, including the EPA and state environmental 
agencies and/or attorneys general.  We may incur significant additional costs beyond those currently contemplated to comply with t
these regulatory requirements.  If we fail to comply with these regulatory requirements, we could be subject to administrative,
civil or criminal liabilities and fines.  Existing environmental regulations could be revised or reinterpreted, new laws and regulations
could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could 
occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant 
additional costs beyond those currently contemplated to comply with existing requirements.  Any of the foregoing could have a 
material adverse effect on us.

The EPA has recently finalized or proposed several regulatory actions establishing new requirements for control of certain
emissions from sources, including electricity generation facilities.  In the future, the EPA may also propose and finalize additional
regulatory  actions  that  may  adversely  affect  our  existing  generation  facilities  or  our  ability  to  cost-effectively  develop  new
generation facilities.  There is no assurance that the currently installed emissions control equipment at our lignite, coal and/or 
natural gas-fueled generation facilities will satisfy the requirements under any future EPA or state environmental regulations.  
Some of the recent regulatory actions and proposed actions, such as the EPA's Regional Haze Federal Implementation Plans (FIP) 
for reasonable progress and best available retrofit technology (BART), could require us to install significant additional control
equipment, resulting in potentially material costs of compliance for our generation units, including capital expenditures, higher 
operating and fuel costs and potential production curtailments if the rules take effect as proposed or finalized.  These costs could 
have a material adverse effect on us.

dd

We may not be able to obtain or maintain all required environmental regulatory approvals.  If there is a delay in obtaining
any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval 
is retroactively disallowed or adversely modified, the operation of our generation facilities could be stopped, disrupted, curtailed 
or modified or become subject to additional costs.  Any such stoppage, disruption, curtailment, modification or additional costs
could have a material adverse effect on us.

In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that 
we have acquired, leased or developed, regardless of when the liabilities arose and whether they are now known or unknown.  In 
connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certainrr
environmental liabilities.  Another party could, depending on the circumstances, assert an environmental claim against us or fail
to meet its indemnification obligations to us.

28

We could be materially and adversely affected if current regulations are implemented or if new federal or state legislation or 
regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or 
property resulting from greenhouse gas emissions.

There is a concern nationally and internationally about global climate change and how GHG emissions, such as CO2, contribute 
to global climate change.  Over the last several years, the U.S. Congress has considered and debated, and President Obama's 
administration previously discussed, several proposals intended to address climate change using different approaches, including
a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG
emissions, incentives for the development of low-carbon technology and federal renewable portfolio standards.  In October 2015,
the EPA finalized regulations under the CAA to limit CO2 emissions from existing generating units, referred to as the Clean Power 
Plan.  If implemented as finalized, the Clean Power Plan would require the closure of a significant number of coal-fueled electricity
generation units nationwide and in Texas.  The Clean Power Plan is currently stayed pending the conclusion of legal challenges 
on the rule.  In October 2017, the EPA proposed the repeal of the Clean Power Plan.  In addition, a number of federal court cases
have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could 
establish adverse precedent that might apply to companies (including us) that produce GHG emissions.  We could be materially
and adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change, if the 
Clean Power Plan is implemented as finalized or if we are subject to lawsuits for alleged damage to persons or property resulting 
from GHG emissions.

tt

The integration of the Capacity Performance product into the PJM market and the Pay-for-Performance mechanism in ISO-
NE could lead to substantial changes in capacity income and non-performance penalties, which could have a material adverse
effect on our results of operations, financial condition and cash flows.

Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time
generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity.  We may
experience substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on 
our results of operations, financial condition and cash flows.

The availability and cost of emission allowances could adversely impact our costs of operations.

We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2,  CO2 and NOX
to support our operations in the ordinary course of operating our power generation facilities.  These allowances are used to meet 
the obligations imposed on us by various applicable environmental laws.  If our operational needs require more than our allocated 
allowances, we may be forced to purchase such allowances on the open market, which could be costly.  If we are unable to maintain
sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our 
available emission allowances or install costly new emission controls.  As we use the emission allowances that we have purchased 
on the open market, costs associated with such purchases will be recognized as operating expense.  If such allowances are available 
for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations
in the affected markets.

Luminant's mining operations are subject to RCT oversight.

We currently own and operate, or are in the process of reclamation, 12 surface lignite coal mines in Texas to provide fuel 
for our electricity generation facilities.  We also own or lease, and are in the process of reclaiming, two waste-to-energy surface 
facilities in Pennsylvania.  The RCT, which exercises broad authority to regulate reclamation activity, reviews on an ongoing basis
whether Luminant is compliant with RCT rules and regulations and whether it has met all the requirements of its mining permits.  
Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface Mining, which also regulates 
mining activity nationwide, or any changes in the interpretation of existing rules and regulations, could result in higher compliance
costs or otherwise adversely affect our financial condition or cause a revocation of a mining permit.  Any revocation of a mining 
permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities.  
In addition, Luminant's mining reclamation obligations are secured by a first lien on its assets which is pari passu with the Vistra 
Operations Credit Facilities, but which would be paid first, up to $975 million, upon any liquidation of Vistra Operations' assets. 
The RCT could, at any time, require that Luminant's mining reclamation obligations be secured by cash or letters of credit in lieu 
of such first lien.  Any failure to provide any such cash or letter of credit collateral could result in Luminant no longer being able 
to mine lignite.  Any such event could have a material adverse effect on us.

VV

29

Luminant's lignite mining reclamation activity will require significant resources as existing and retired mining operations are
reclaimed over the next several years.

In conjunction with Luminant's announcements in the third and fourth quarters of 2017 to retire several power generation
assets and related mining operations, along with the continuous reclamation activity at its continuing mining operations for its 
mines related to the Oak Grove and Martin Lake generation assets, Luminant is expected to spend a significant amount of money, 
internal resources and time to complete the required reclamation activities.  For the next five years, Vistra Energy is projected to
spend approximately $340 million (on a nominal basis) to achieve its reclamation objectives.

Litigation,  legal  proceedings,  regulatory  investigations  or  other  administrative  proceedings  could  expose  us  to  significant 
liabilities and reputation damage that could have a material adverse effect on us.

We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment, 
commercial,  and  environmental  issues,  and  other  claims  for  injuries  and  damages.    We  evaluate  litigation  claims  and  legal
proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses.  Based 
on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant a
litigation claims or legal proceedings, as appropriate.  These evaluations and estimates are based on the information available to 
management at the time and involve a significant amount of judgment.  Actual outcomes or losses may differ materially from 
current evaluations and estimates.  The settlement or resolution of such claims or proceedings may have a material adverse effect 
on us.  We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant 
business risk.

We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, 
and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. 
While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation 
or administrative proceeding could result in us incurring material penalties and/or other costs and have a materially adverse effect 
on us.

Our retail businesses, which each have REP certifications that are subject to review of the public utility commissions in the 
states  in  which  we  operate,  are  subject  to  changing  state  rules  and  regulations  that  could  have  a  material  impact  on  the
profitability of our business.

The competitiveness of our retail businesses partially depends on state regulatory policies that establish the structure, rules, 
terms and conditions on which services are offered to retail customers.  Specifically, the public utility commissions and/or the
attorney generals of the various jurisdictions in which the Retail segment operates may at any time initiate an investigation into
whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for 
REP certification, including financial requirements. These state policies and investigations, which can include controls on the
retail rates our retail businesses can charge, the imposition of additional costs on sales, restrictions on our ability to obtain new
customers  through  various  marketing  channels  and  disclosure  requirements,  investigations  into  whether  our  retail  operations
comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including 
financial requirements, can affect the competitiveness of our retail businesses.  Any removal or revocation of a REP certification
would mean that we would no longer be allowed to provide electricity service to retail customers in the applicable jurisdiction, 
and such decertification could have a material adverse effect on us. Additionally, state or federal imposition of net metering or 
renewable portfolio standard programs can make it more or less expensive for retail customers to supplement or replace their 
reliance on grid power.  Our retail businesses have limited ability to influence development of these state rules, regulations and 
policies, and our business model may be more or less effective, depending on changes to the regulatory environment.

30

Operational Risks

p

Volatile power supply costs and demand for power could adversely affect the financial performance of our retail businesses.

Although we are the primary provider of our retail businesses' wholesale electricity supply requirements, our retail businesses
purchase a significant portion of their supply requirements from third parties.  As a result, the financial performance of our retail 
business depends on their ability to obtain adequate supplies of electric generation from third parties at prices below the prices
they charge their customers.  Consequently, our earnings and cash flows could be adversely affected in any period in which the
retail businesses' wholesale electricity supply costs rise at a greater rate than the rates they charge to customers.  The price of 
wholesale electricity supply purchases associated with the retail businesses' energy commitments can be different than that reflected 
in the rates charged to customers due to, among other factors:

ff

• 
• 
• 
• 
• 

varying supply procurement contracts used and the timing of entering into related contracts;
subsequent changes in the overall price of natural gas;
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
transmission constraints and the Company's ability to move power to our customers, and
changes in market heat rate.

The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers' actual 
usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors, weather events,
competition and economic conditions.

Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customersrr
and the inability to attract new customers.

We operate in a very competitive retail market and, as a result, our retail operation faces significant competition for customers.  
We believe our TXU EnergyTM, Homefield Energy and Dynegy Energy Services brands are viewed favorably in the retail electricity 
markets in which we operate, but despite our commitment to providing superior customer service and innovative products, customer 
sentiment toward our brands, including by comparison to our competitors' brands, depends on certain factors beyond our control.  
For example, competitor REPs may offer different products, lower electricity prices and other incentives, which, despite our long-
standing relationship with many customers, may attract customers away from us.  If we are unable to successfully compete with 
competitors in the retail market it is possible our retail customer counts could decline, which could have a material adverse effect 
on us.

As we try to grow our retail business and operate our business strategy, we compete with various other REPs that may have
certain advantages over us.  For example, in new markets, our principal competitor for new customers may be the incumbent REP,
which has the advantage of long-standing relationships with its customers, including well-known brand recognition.  In addition
to competition from the incumbent REP, we may face competition from a number of other energy service providers, other energy 
industry participants, or nationally branded providers of consumer products and services who may develop businesses that will
compete with us.  Some of these competitors or potential competitors may be larger than we are or have greater resources or access
to capital than we have.  If there is inadequate potential margin in retail electricity markets with substantial competition to overcome 
the adverse effect of relatively high customer acquisition costs in such markets, it may not be profitable for us to compete in these
markets.

n

31

Our  retail  operations  rely  on  the  infrastructure  of  local  utilities  or  independent  transmission  system  operators  to  provide 
electricity to, and to obtain information about, our customers.  Any infrastructure failure could negatively impact customer 
satisfaction and could have a material adverse effect on us.

With the exception of Electric Energy, Inc. (EEI), which we acquired in the Merger and which owns and controls transmission
lines interconnecting our Joppa facility in EEI’s control to MISO, Tennessee Valley Authority and Louisville Gas and Electric 
Company, our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities to
deliver the electricity that we sell to our customers.  If transmission capacity is inadequate, our ability to sell and deliver electricity 
may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-
constrained area, or, with respect to capacity performance in PJM and performance incentives in ISO-NE, we may be subject to
significant penalties.  For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth WW
metroplex, where we have a significant number of customers.  The cost to provide service to these customers may exceed the cost
to provide service to other customers, resulting in lower operating margins.  In addition, any infrastructure failure that interrupts
or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service.  Any of the
foregoing could have a material adverse effect on us.

r

The operation of our businesses is subject to cyber-based security and integrity risk.  Attacks on our infrastructure that breach 
cyber/data security measures could expose us to significant liabilities and reputation damage and disrupt business operations, 
which could have a material adverse effect on us.

Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, 
processing and communication of electronic data and the use of sophisticated computer hardware and software systems and much 
of our information technology infrastructure is connected (directly or indirectly) to the internet.  There have been numerous attacks
on  government  and  industry  information  technology  systems  through  the  internet  that  have  resulted  in  material  operational, 
reputation and/or financial costs.  While we have controls in place designed to protect our infrastructure and we are not aware of 
any significant breaches in the past, a breach of cyber/data security measures that impairs our information technology infrastructure
could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information 
and limit communication with third parties.  Any loss of confidential or proprietary data through a breach could adversely affect 
our reputation, expose us to material legal or regulatory claims and impair our ability to execute our business strategy, which could 
have a material adverse effect on us.  In addition, we may experience increased capital and operating costs to implement increased 
security for our information technology infrastructure and plants.

h

aa

rr

As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its 
Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets." 
Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for failure to complym
with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from
cyber/data and physical security breaches.

r

Further, our retail business requires access to sensitive customer data in the ordinary course of business.  Examples of sensitive 
customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history,rr
credit bureau data, credit and debit card account numbers, drivers' license numbers, social security numbers and bank account 
information.  Our retail business may need to provide sensitive customer data to vendors and service providers who require access
to this information in order to provide services, such as call center operations, to the retail business.  If a significant breach were 
to occur, the reputation of our retail business may be adversely affected, customer confidence may be diminished, and our retail 
business may be subject to substantial legal or regulatory claims, any of which may contribute to the loss of customers and have
a material adverse effect on us.

We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation 
facility.

We own and operate a nuclear generation facility in Glen Rose, Texas (Comanche Peak Facility).  The ownership and operation 

of a nuclear generation facility involves certain risks. These risks include:

• 
• 
• 
• 

• 

unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity or other problems;
inadequacy or lapses in maintenance protocols;
the impairment of reactor operation and safety systems due to human error or force majeure;
the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive
materials;
the costs of procuring nuclear fuel;

32

• 
• 
• 
• 
• 

the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;
terrorist or cybersecurity attacks and the cost to protect against any such attack;
the impact of a natural disaster;
limitations on the amounts and types of insurance coverage commercially available, and
uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities
at the end of their useful lives.

Any prolonged unavailability of the Comanche Peak Facility could have a material adverse effect on our results of operation, 

cash flows, financial position and reputation.  The following are among the more significant related risks:

k

•  Operational Risk — Operations at any generation facility could degrade to the point where the facility would have to be
shut down.  If such degradations were to occur at the Comanche Peak Facility, the process of identifying and correcting 
the causes of the operational downgrade to return the facility to operation could require significant time and expense, 
resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments.  Furthermore, 
a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced 
availability at the Comanche Peak Facility.

k

•  Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply
with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities.  Unless 
extended, as to which no assurance can be given, the NRC operating licenses for the two licensed operating units at the
Comanche Peak Facility will expire in 2030 and 2033, respectively.  Changes in regulations by the NRC, as well as any 
extension of our operating licenses, could require a substantial increase in capital expenditures or result in increased 
operating or decommissioning costs.

•  Nuclear Accident Risk — Although the safety record of the Comanche Peak Facility and other nuclear generation facilities

k

generally has been very good, accidents and other unforeseen problems have occurred both in the U.S. and elsewhere.  
The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property 
damage.  Any accident, or perceived accident, could result in significant liabilities and damage our reputation.  Any such 
resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately 
result in the suspension or termination of power generation from the Comanche Peak Facility.

The operation and maintenance of power generation facilities and related mining operations involve significant risks that 
could adversely affect our results of operations, liquidity and financial condition.

The operation and maintenance of power generation facilities and related mining operations involve many risks, including, 
as applicable, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of sufficient capital to
maintain the facilities, the dependence on a specific fuel source, the inability to transport our product to our customers in an a
efficient manner due to the lack of transmission capacity or the impact of unusual or adverse weather conditions or other natural 
events, or terrorist attacks, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence
of any of which could result in substantial lost revenues and/or increased expenses.  A significant number of our facilities were 
constructed many years ago.  Older generating equipment, even if maintained or refurbished in accordance with good engineering
practices, may require significant capital expenditures to operate at peak efficiency or reliability.  The risk of increased maintenance 
and  capital  expenditures  arises  from  (a)  increased  starting  and  stopping  of  generation  equipment  due  to  the  volatility  of  the 
competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or
year-round operation of all our generation facilities, (b) any unexpected failure to generate power, including failure caused by
equipment breakdown or unplanned outage (whether by order of applicable governmental regulatory authorities, the impact of 
weather events or natural disasters or otherwise), (c) damage to facilities due to storms, natural disasters, wars, terrorist or cyber/
data security acts and other catastrophic events and (d) the passage of time and normal wear and tear.  Further, our ability to
successfully and timely complete routine maintenance or other capital projects at our existing facilities is contingent upon many 
variables and subject to substantial risks.  Should any such efforts be unsuccessful, we could be subject to additional costs or losses
and write downs of our investment in the project.

a

We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws 
and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events
(such as natural disasters or terrorist or cyber/data security attacks).  The unexpected requirement of large capital expenditures 
could have a material adverse effect on us.  Moreover, if we significantly modify a unit, we may be required to install the best 
available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source
review provisions of the CAA, which would likely result in substantial additional capital expenditures.

uu

33

In addition, unplanned outages at any of our generation facilities, whether because of equipment breakdown or otherwise, 
typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or non-
performance penalties or require us to incur significant costs as a result of running one of our higher cost units or to procure 
replacement power at spot market prices in order to fulfill contractual commitments.  If we do not have adequate liquidity to meet 
margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have
increased exposure to the volatility of spot markets, which could have a material adverse effect on us.  Further, our inability toy
operate our generation facilities efficiently, manage capital expenditures and costs, and generate earnings and cash flow from our 
asset-based businesses could have a material adverse effect on our results of operations, financial condition or cash flows.  While
we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds
of such insurance, warranties or performance guarantees may not be adequate to cover our lost revenues, increased expenses or 
liquidated damages payments should we experience equipment breakdown or non-performance by contractors or vendors.

Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have
a material adverse effect on Vistra Energy's revenues and results of operations, and Vistra Energy may not have adequate 
insurance to cover these risks and hazards.  Our employees, contractors, customers and the general public may be exposed to
a risk of injury due to the nature of our operations.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces 
of equipment and delivering electricity to transmission and distribution systems.  In addition to natural risks such as earthquake,
flood, lightning, hurricane and wind, other hazards, such as nuclear accidents, dam failure, gas or other explosions, mine area
collapses, fire, structural collapse, machinery failure and other dangerous incidents are inherent risks in our operations.  These
and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and 
equipment, contamination of, or damage to, the environment and suspension of operations.  Further, our employees and contractors
work in, and customers and the general public may be exposed to, potentially dangerous environments at or near our operations. 
As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life.

The occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for 
substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. 
We maintain an amount of insurance protection that we consider adequate, but we cannot provide any assurance that our insurance
will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject and, even
if we do have insurance coverage for a particular circumstance, we may be subject to a large deductible and maximum cap.  A 
successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. 
Further, due to rising insurance costs and changes in the insurance markets, we cannot provide any assurance that our insurance
coverage will continue to be available at all or at rates or on terms similar to those presently available.  Any losses not covered 
by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

We may be materially and adversely affected by the effects of extreme weather conditions and seasonality.

We may be materially affected by weather conditions and our businesses may fluctuate substantially on a seasonal basis as 
the weather changes.  In addition, we could be subject to the effects of extreme weather conditions, including sustained cold or 
hot temperatures, hurricanes, storms or other natural disasters, which could stress our generation facilities and result in outages,
destroy our assets and result in casualty losses that are not ultimately offset by insurance proceeds, and could require increased 
capital expenditures or maintenance costs, including supply chain costs.

Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage 
to other operating equipment, which could result in us foregoing sales of electricity and lost revenue.  Similarly, an extreme weather 
event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver power where
it is needed or limit our ability to source fuel for our plants (including due to damage to rail or natural gas pipeline infrastructure). 
Additionally, extreme weather may result in unexpected increases in customer load, requiring our retail operation to procure
additional electricity supplies at wholesale prices in excess of customer sales prices for electricity.  These conditions, which cannot 
be reliably predicted, could have adverse consequences by requiring us to seek additional sources of electricity when wholesale
market prices are high or to sell excess electricity when market prices are low, which could have a material adverse effect on us.

34

Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and may
otherwise have a material adverse effect on us.

Technological advances have improved, and are likely to continue to improve, for existing and alternative methods to produce 
and  store  power,  including  gas  turbines,  wind  turbines,  fuel  cells,  micro  turbines,  photovoltaic  (solar)  cells,  batteries  and 
concentrated  solar  thermal  devices,  along  with  improvements  in  traditional  technologies.    Such  technological  advances  have 
reduced, and are expected to continue to reduce, the costs of power production or storage to a level that will enable these technologies
to compete effectively with traditional generation facilities.  Consequently, the value of our more traditional generation assets
could be significantly reduced as a result of these competitive advances, which could have a material adverse effect on us.  In
addition, changes in technology have altered, and are expected to continue to alter, the channels through which retail customers
buy electricity (i.e., self-generation or distributed-generation facilities).  To the extent self-generation facilities become a more 
cost-effective option for customers, our financial condition, operating cash flows and results of operations could be materially and 
adversely affected.

Technological advances in demand-side management and increased conservation efforts have resulted, and are expected to 
continue to result, in a decrease in electricity demand.  A significant decrease in electricity demand as a result of such efforts would 
significantly reduce the value of our generation assets.  Certain regulatory and legislative bodies have introduced or are considering 
requirements and/or incentives to reduce power consumption.  Effective power conservation by our customers could result in
reduced electricity demand or significantly slow the growth in such demand.  Any such reduction in demand could have a material
adverse effect on us.  Furthermore, we may incur increased capital expenditures if we are required to increase investment in
conservation measures.

The loss of the services of our key management and personnel could adversely affect our ability to successfully operate our 
businesses.

Our future success will depend on our ability to continue to attract and retain highly qualified personnel.  We compete for 
such personnel with many other companies, in and outside of our industry, government entities and other organizations.  We may 
not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future.  Our failure to attract 
highly  qualified  new  personnel  or  retain  highly  qualified  existing  personnel  could  have  an  adverse  effect  on  our  ability  to 
successfully operate our businesses.

We could be materially and adversely impacted by strikes or work stoppages by our unionized employees.

As of December 31, 2018, we had approximately 2,030 employees covered by collective bargaining agreements, of which 
approximately 945 are subject to collective bargaining agreements entered into by Dynegy and assumed by us in the Merger.  The 
terms of all collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-
and nuclear-fueled generation operation and some of our natural gas-fueled generation operations expire on various dates between 
March 2019 and March 2022, but remain effective from-year-to-year thereafter unless and until terminated by either party.  In the 
event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or 
disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. 
Our ability to procure such labor is uncertain.  Strikes, work stoppages or the inability to negotiate current or future collective
bargaining agreements on favorable terms or at all could have a material adverse effect on us.

t

Risks Related to Our Structure and Ownership of our Common Stock

p

Vistra Energy is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to existing 
and future liabilities and preferred equity of its subsidiaries.

ii

Vistra Energy is a holding company that does not conduct any business operations of its own.  As a result, Vistra Energy's
cash flows and ability to meet its obligations are largely dependent upon the operating cash flows of Vistra Energy's subsidiaries
and the payment of such operating cash flows to Vistra Energy in the form of dividends, distributions, loans or otherwise.  These
subsidiaries are separate and distinct legal entities from Vistra Energy and have no obligation (other than any existing contractual 
obligations) to provide Vistra Energy with funds to satisfy its obligations.  Any decision by a subsidiary to provide Vistra Energy 
with funds to satisfy its obligations, including those under the TRA, whether by dividends, distributions, loans or otherwise, will
depend  on,  among  other  things,  such  subsidiary's  results  of  operations,  financial  condition,  cash  flows,  cash  requirements,
contractual prohibitions and other restrictions, applicable law and other factors.  The deterioration of income from, or other available 
assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to Vistra
Energy.

35

We may not pay any dividends on our common stock in the future.

In November 2018, we announced that the Board had adopted a dividend program pursuant to which we expect to initiate 
an annual dividend of approximately $0.50 per share, payable quarterly, beginning in the first quarter of 2019.  Each dividend 
under the program will be subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the
time of any such declaration including, but not limited to, prevailing market conditions, our results of operations, financial condition 
and liquidity, contractual prohibitions and other restrictions with respect to the payment of dividends.  There is no assurance that 
the Board will declare, or that we will pay, any dividends on our common stock in the future.

A small number of stockholders could be able to significantly influence or impact our business and affairs.

Three of the largest groups of stockholders of Vistra Energy, affiliates of Brookfield Asset Management Private Institutional 
Capital Adviser (Canada), L.P. (collectively, the Brookfield Entities), affiliates of Oaktree Capital Management, L.P. (collectively, 
the Oaktree Entities), and affiliates of Apollo Management Holdings L.P. (collectively, the Apollo Entities, and together with the 
Brookfield Entities and the Oaktree Entities, the Principal Stockholders), all of which were first lien creditors of our Predecessor 
prior to Emergence, currently collectively own approximately 26% of our common stock outstanding.  Large holders such as the
Principal Stockholders may be able to affect matters requiring approval by holders of our common stock, including the election 
of directors and the approval of any strategic transactions.  Furthermore, pursuant to the terms of stockholders' agreements entered 
into with each of the Brookfield Entities and the Apollo Entities, each such Principal Stockholder is entitled to designate one
director to serve on the Board as a Class III director for so long as it beneficially owns, in the aggregate, at least 22,500,000 shares
of our common stock.

Additionally, we may be subject, from time to time, to legal and business challenges in the operation of our company due
to actions instituted by activist shareholders or others. Responding to such actions, which may include private engagement, publicity 
campaigns, proxy contests, efforts to force transactions not supported by our Board, and litigation, could be costly and time-
consuming, may not align with our strategic plan and could divert the time and attention of our Board and management from our 
business.

Item 1B.  UNRESOLVED STAFF COMMENTS

None.

36

Item 2. 

PROPERTIES

Luminant's generation fleet consists of power generation units in six RTOs/ISOs, with the location, RTO/ISO, technology,

primary fuel type, net capacity and ownership interest for each generation facility shown in the table below:

Facility

Ennis
Forney
Hays
Lamar
Midlothian
Odessa
Wise
Coleto Creek
Martin Lake
Oak Grove
DeCordova
Graham
Lake Hubbard
Morgan Creek
Permian Basin
Stryker Creek
Trinidad
Wharton
Comanche Peak
Upton 2
Upton 2 Battery Storage

Location

Ennis, TX
Forney, TX
San Marcos, TX
Paris, TX
Midlothian, TX
Odessa, TX
Poolville, TX
Goliad, TX
Tatum, TX
Franklin, TX
Granbury, TX
Graham, TX
Dallas, TX
Colorado City, TX
Monahans, TX
Rusk, TX
Trinidad, TX
Boling, TX
Glen Rose, TX
Upton County, TX
Upton County, TX

Total ERCOT Segment

Fayette
Hanging Rock
Hopewell
Kendall
Liberty
Ontelaunee
Sayreville
Washington
Kincaid
Miami Fort 7 & 8
Zimmer
Calumet
Dicks Creek
Miami Fort (CT)
Pleasants
Richland
Stryker

Total PJM Segment

Masontown, PA
Ironton, OH
Hopewell, VA
Minooka, IL
Eddystone, PA
Reading, PA
Sayreville, NJ
Beverly, OH
Kincaid, IL
North Bend, OH
Moscow, OH
Chicago, IL
Monroe, OH
North Bend, OH
Saint Marys, WV
Defiance, OH
Stryker, OH

Technology
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
ST
ST
ST
CT
ST
ST
CT
CT
ST
ST
CT
Nuclear
Solar
Battery

CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
ST
ST
ST
CT
CT
CT
CT
CT
CT

Primary Fuel
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Coal
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Nuclear
Solar
Battery

Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Coal
Coal
Natural Gas
Natural Gas
Oil
Natural Gas
Natural Gas
Oil

Net Capacity
(MW) (a)

366
1,912
1,047
1,076
1,596
1,054
787
650
2,250
1,600
260
630
921
390
325
685
244
83
2,300
180
10
18,366
726
1,430
370
1,288
607
600
170
711
1,108
1,020
1,300
380
155
77
388
423
16
10,769

Ownership
Interest
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%

100%
100%
100%
100%
100%
100%
50%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%

RTO/ISO
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT

PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM

37

Facility

Bellingham
Bellingham NEA
Blackstone
Casco Bay
Independence
Lake Road
MASSPOWER
Milford

Location
Bellingham, MA
Bellingham, MA
Blackstone, MA
Veazie, ME
Oswego, NY
Dayville, CT
Indian Orchard, MA
Milford, CT

Total NY/NE Segment

Baldwin, IL
Havana, IL
Hennepin, IL
Coffeen, IL
Canton, IL
Bartonville, IL
Newton, IL
Joppa, IL
Joppa, IL
Joppa, IL

Baldwin
Havana
Hennepin
Coffeen
Duck Creek
Edwards
Newton
Joppa/EEI
Joppa CT 1-3
Joppa CT 4-5

Total MISO Segment

Moss Landing 1 & 2
Oakland

Total CAISO

Total capacity

RTO/ISO
ISO-NE
ISO-NE
ISO-NE
ISO-NE
NYISO
ISO-NE
ISO-NE
ISO-NE

MISO
MISO
MISO
MISO/PJM
MISO/PJM
MISO/PJM
MISO/PJM
MISO
MISO
MISO

Technology
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT

ST
ST
ST
ST
ST
ST
ST
ST
CT
CT

Primary Fuel
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas

Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Natural Gas
Natural Gas

Ownership
Interest
100%
50%
100%
100%
100%
100%
100%
100%

100%
100%
100%
100%
100%
100%
100%
80%
100%
80%

100%
100%

Net Capacity
(MW) (a)

566
157
544
543
1,212
827
281
600
4,730
1,185
434
294
915
425
585
615
802
165
56
5,476
1,020
165
1,185
40,526

Moss Landing, CA
Oakland, CA

CAISO
CAISO

CCGT
CT

Natural Gas
Oil

___________
(a)  Unit capabilities are based on winter capacity and are reflected at our net ownership interest.  We have not included units

that have been retired or are out of operation.

Our wholesale commodity risk management group also procures renewable energy credits from wind generation in ERCOT
to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for renewable resources from 
such customers.  As of December 31, 2018, Vistra Energy had long-term power purchase agreements to procure approximately 
480 MW of available renewable capacity.  These renewable generation sources deliver electricity when conditions make them
available, and, when on-line, they generally compete with baseload units.  Because they cannot be relied upon to meet demand 
continuously due to their dependence on weather and time of day, these generation sources are categorized as non-dispatchable
and create the need for intermediate/load-following resources to respond to changes in their output.

Fuel Supply

—

Nuclear — We operate two nuclear generation units at the Comanche Peak plant site in ERCOT, each of which is designed 
for a capacity of 1,150 MW.  Comanche Peak Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, 
and are generally operated at full capacity.  Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to 
occur every eighteen months during the spring or fall off-peak demand periods.  Every three years, the refueling cycle results in
the refueling of both units during the same year, the latest of which occurred during 2017.  While one unit is undergoing a refueling 
outage, the remaining unit is intended to operate at full capacity.  During a refueling outage, other maintenance, modification and 
testing activities are completed that cannot be accomplished when the unit is in operation.  The Comanche Peak facility operated 
at a capacity factor of 101%, 84% and 101% in 2018, 2017 and 2016, respectively.  The capacity factor for the year ended December 
31, 2017 reflected an unplanned outage at one of the units between June and August 2017.

d

n

ff

We have contracts in place for our 2019 and 2020 nuclear fuel requirements.  We do not anticipate any significant difficulties

in acquiring uranium and contracting for associated conversion, enrichment and fabrication services in the foreseeable future.

38

—

Coal/Lignite — Our coal/lignite-fueled generation fleet is comprised of 14 generation facilities totaling 13,183 MW of 
generation capacity.  Maintenance outages at these units are scheduled during the spring or fall off-peak demand periods.  We 
meet our fuel requirements at our coal-fueled generation facilities in PJM and MISO with coal purchased from multiple suppliers
under contracts of various lengths and transported to the facilities by either railcar or barges.  We meet our fuel requirements in
ERCOT using lignite that we mine at the Oak Grove generation facility, coal purchased and transported by railcar at the Coleto 
Creek generation facility and a blend of lignite that we mine and coal purchased and transported by railcar at our Martin Lake 
generation facility.

—

Natural Gas — Our natural gas-fueled generation fleet is comprised of 24 CCGT generating facilities totaling 19,490 MW 
and 14 peaking generation facilities totaling 5,105 MW.  We satisfy our fuel requirements at these facilities through a combination
of spot market and near-term purchase contracts.  Additionally, we have near-term natural gas transportation agreements in place
to ensure reliable fuel supply.

aa

Item 3.  LEGAL PROCEEDINGS

See Note 15 to the Financial Statements for discussion of litigation, including matters related to our generation facilities 

and EPA reviews.

Item 4.  MINE SAFETY DISCLOSURES

Vistra Energy currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to provide
fuel for its electricity generation facilities.  Vistra Energy also owns or leases, and is in the process of reclaiming, two waste-to-
energy surface facilities in Pennsylvania.  These mining operations are regulated by the MSHA under the Federal Mine Safety 
and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and 
Office of Surface Mining.  The MSHA inspects U.S. mines, including Vistra Energy's mines, on a regular basis, and if it believes
a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, rr
generally accompanied by a proposed fine or assessment.  Such citations and orders can be contested and appealed, which often
results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal.  Disclosure of MSHA 
citations, orders and proposed assessments are provided in Exhibit 95.1 to this Annual Report on Form 10-K.

39

PART II

Item 5.  MARKET  FOR  REGISTRANT'S  COMMON  EQUITY,  RELATED  STOCKHOLDER  MATTERS  AND 

ISSUER PURCHASES OF EQUITY SECURITIES

Vistra Energy's authorized capital stock consists of 1,800,000,000 shares of common stock with a par value of $0.01 per 

share.

Since May 10, 2017, Vistra Energy's common stock has been listed on the NYSE under the symbol "VST".  Upon Emergence

and through May 9, 2017, Vistra Energy's common stock was listed on the OTCQX U.S. under the symbol "VSTE".

On April 9, 2018 (Merger Date), pursuant to the Merger Agreement, 94,409,573 shares of Vistra Energy common stock were 
issued to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible equity units and 
warrants.

As of February 25, 2019, there were 485,894,408 shares of common stock issued and outstanding and 630 shareholders of 

record.

Vistra Energy paid a one-time 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.  In November 2018, we announced that the Board had 
adopted a dividend program pursuant to which we expect to initiate an annual dividend of approximately $0.50 per share, payable
quarterly, beginning in the first quarter of 2019.  Each dividend under the program will be subject to declaration by the Board and,
thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing 
market conditions, our results of operations, financial condition and liquidity and Delaware law.  For additional details, see Item
1A. Risk Factors and Note 16 to the Financial Statements

d

Subject to limitations under applicable Delaware law, preferences that may apply to any outstanding shares of our preferred 
stock and contractual restrictions, holders of our common stock are entitled to receive dividends or other distributions ratably,
when, as and if declared by the Board.  The ability of the Board to declare dividends with respect to our common stock, however, rr
will be subject to such limitations, preferences and restrictions and the availability of sufficient funds under the Delaware General
Corporation Law (DGCL) to pay such dividends.

40

Stock Performance Graph

The performance graph below compares Vistra Energy's cumulative total return on common stock for the period from May
10, 2017 through December 31, 2018 with the cumulative total returns of the S&P 500 Stock Index (S&P 500) and the S&P Utility 
Index (S&P Utilities).  The graph below compares the return in each period assuming that $100 was invested at May 10, 2017 in 
Vistra Energy's common stock, the S&P 500 and the S&P Utilities, and that all dividends were reinvested.

Comparison of Cumulative Total Return

$160

$150

$140

$130

$120

$110

$100

$90

Vistra Energy
Corp.

S&P 500

S&P Utilities

05/10/17

.

.

12/31/17

.

.

.

12/31/18

Share Repurchase Program

The following table provides information about our repurchase of equity securities that are registered by us pursuant to

Section 12 of the Securities Exchange Act of 1934, as amended, during the quarter ended December 31, 2018.

Total Number
of Shares
Purchased

Average
Price Paid
per Share

Total Number of Shares
Purchased as Part of a
Publicly Announced
Program

Maximum Dollar Amount
of Shares that may yet be
Purchased under the
Program (in millions)

October 1 - October 31, 2018

November 1 - November 30, 2018

December 1 - December 31, 2018

3,150,820

6,238,950

5,834,141

For the quarter ended December 31, 2018

15,223,911

$

$

$

$

24.38

22.99

22.99

23.28

3,150,820

6,238,950

5,834,141

15,223,911

$

$

$

$

—

1,107

972

972

In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of 
our outstanding common stock could be repurchased.  This share repurchase program was effective as of June 13, 2018, and the
program was completed on October 19, 2018.

In November 2018, we announced that the Board had authorized an incremental share repurchase program under which up
to $1.25 billion of our outstanding stock may be purchased.  We intend to implement the program opportunistically from time to
time over approximately the next 12 months.

Shares of the Company's stock will be repurchased from time to time in open market transactions at prevailing market prices,
in privately negotiated transactions, pursuant to plans complying with Rule 10b5-1 and 10b-18 under the Securities Exchange Act
of 1934, as amended, or by other means in accordance with federal securities laws.  The actual timing, number and value of shares
repurchased under the share repurchase program will be determined at our discretion and will depend on a number of factors, 
including the market price of our stock, general market and economic conditions, applicable legal requirements and compliance
with the terms of our debt agreements.

41

Item 6. 

SELECTED FINANCIAL DATA

VISTRA ENERGY CORP.
SELECTED CONSOLIDATED FINANCIAL INFORMATION
(Millions of Dollars, Except Per Share Amounts and Ratios

Successor

Predecessor

Operating revenues
Impairment of goodwill
Impairment of long-lived assets
Operating income (loss)
Net income (loss) attributable to Vistra
Energy/the Predecessor (b)
Cash provided by (used in) operating
activities
Net loss per weighted average share of
common stock outstanding — basic
Net loss per weighted average share of
common stock outstanding — diluted
Dividend declared per share of
common stock

$
$
$
$

$

$

$

$

$

Year Ended
December 31,
2018 (a)

Year Ended
December 31,
2017

Year Ended
December 31,

5,430

Period from
October 3, 2016
through
December 31, 2016
1,191
$
— $
(25) $
$
198

Period from
January 1, 2016 
through
October 2, 2016
$
3,973
— $
— $
$

(161)

$

$

2015
5,370

2014
5,978
— $ (2,200) $ (1,600)
— $ (2,541) $ (4,670)
$ (4,091) $ (6,015)
568

9,144 $
— $
— $
491 $

$

$

22,851

$ (4,677) $ (6,229)

(238) $

237

$

444

(54) $

(254) $

(163)

1,471 $

1,386

$

(0.11) $

(0.59) $

(0.11) $

(0.59) $

— $

— $

81

(0.38)

(0.38)

2.32

Successor

At December 31,

Predecessor

At December 31,

2018

2017

2016

2015

2014

Balance Sheet Information:
Total assets (c)(d)
Property, plant and equipment — net (c)(d)
Goodwill and intangible assets (e)
Long-term debt including current maturities (e)
Borrowings under debtor-in-possession credit facility
Pre-Petition notes, loans and other debt reported as liabilities
subject to compromise (e)
Total stockholders' equity/membership interests

$ 26,024
$ 14,612
$
4,561
$ 11,065
$

$ 14,600
4,820
$
4,437
$
$
4,423
— $

$ 15,167
4,443
$
5,112
$
$
4,623
— $

$ 15,658
9,349
$
1,331
$
19
$
1,425
— $

$ 21,343
$ 12,288
3,688
$
73
$
1,425
$

$
$

— $
$

7,863

— $
$

6,342

— $ 31,668

$ 31,856
$ (22,884) $ (18,209)

6,597

___________
(a)  For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.
(b)  For the Predecessor period from January 1, 2016 through October 2, 2016, net income includes net gains totaling $22.121 
billion related to bankruptcy-related reorganization items including gains on extinguishing claims pursuant to the Plan of 
Reorganization (see Notes 5 and 7 to the Financial Statements).
(c)  At December 31, 2018, includes assets acquired in the Merger.
(d)  Reflects the impacts of impairment charges related to long-lived assets of $2.541 billion and $4.670 billion in the years ended 

December 31, 2015 and 2014, respectively (see Note 4 to the Financial Statements).

(e)  As of December 31, 2015 and 2014, includes both unsecured and under secured obligations incurred prior to the Petition 
Date, but excludes pre-petition obligations that were fully secured and other obligations that were allowed to be paid as 
ordered by the Bankruptcy Court.  As of December 31, 2014, also excludes $702 million of deferred debt issuance and 
extension costs.

42

Item 7.  MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF  FINANCIAL  CONDITION  AND  RESULTS  OF 

OPERATIONS

As described in Note 1 to the Financial Statements, Vistra Energy is considered a new reporting entity for accounting purposes 
as of the Effective Date, and its financial statements reflect the application of fresh start reporting.  The financial statements of 
Vistra Energy (the Successor) for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH
(the Predecessor) for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the 
carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization, and the related application of fresh
start reporting, which includes accounting policies implemented by Vistra Energy that may differ from the Predecessor.  See Note
6 to the Financial Statements for further discussion of fresh start reporting.

t

The following discussion and analysis of our financial condition and results of operations for the Successor period for the 
years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor 
period from January 1, 2016 through October 2, 2016 should be read in conjunction with our consolidated financial statements 
and the notes to those statements.  Results are impacted by the effects of the Merger, fresh start reporting, the Bankruptcy Filing 
and the application of Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations.

All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S. dollars unless otherwise

indicated.

Business

Vistra Energy is a holding company operating an integrated power business in markets thorough the U.S.  Through our 
subsidiaries, we are engaged in competitive electricity market activities including power generation, wholesale energy sales and 
purchases, commodity risk management and retail sales of electricity and related services to end users.  Prior to the Effective Date,
TCEH was a holding company for our subsidiaries, which were principally engaged in the same activities as they are today.

Operating Segments

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), 
(v) MISO and (vi) Asset Closure.  The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets
served by businesses acquired in the Merger.  Prior to the Effective Date, there were no reportable business segments for TCEH. 
See Note 22 to the Financial Statements for further information concerning reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

Entry into Purchase Agreement to Acquire Crius Energy Trust

On  February  7,  2019,  Vistra  Energy  and  Crius  Energy  Trust  (Crius)  entered  into  a  definitive  agreement,  which  was
subsequently amended on February 19, 2019 (as amended, the Crius Purchase Agreement), as a result of an unsolicited acquisition
proposal, pursuant to which Vistra Energy will acquire the equity interest of two wholly owned subsidiaries of Crius that indirectly
own the operating business of Crius (Crius Transaction).  Crius is an energy retailer selling both electricity and natural gas products
to residential and small business customers in 19 states and the District of Columbia.

The acquisition provides a high degree of overlap with Vistra Energy's generation fleet with approximately 11.6 TWh of 
annual load, improving Vistra Energy's match of its generation to load profile to approximately 45 percent, reducing risk.  The
acquisition also establishes a platform for future growth by leveraging Vistra Energy's existing retail marketing capabilities and 
Crius's experienced team.  The acquisition enhances the integrated value proposition through collateral and transaction efficiencies,
particularly via Crius's largely retail portfolio.

Vistra Energy intends to fund the purchase price of approximately $378 million using cash on hand and assumption of Crius's 
net debt of approximately $108 million.  Completion of the Crius Transaction is subject to various customary conditions, including,
among others, (i) approval by at least two-thirds of the Crius unitholders and (ii) receipt of all requisite regulatory approvals,
which include approvals of the FERC and the expiration and termination of the applicable waiting period under the Hart-Scott-
Rodino Antitrust  Improvements Act  of  1976.    Pending  the  receipt  of  all  necessary  approvals  and  the  fulfillment  of  all  other 
customary closing conditions, the parties expect the transaction to close in the second quarter of 2019.

43

Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement.  Pursuant 
to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation.

At the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other 
than  shares  owned  by Vistra  Energy  or  its  subsidiaries,  held  in  treasury  by  Dynegy  or  held  by  a  subsidiary  of  Dynegy,  was 
automatically converted into 0.652 shares of common stock, par value $0.01 per share, of Vistra Energy, except that cash was paid 
in lieu of fractional shares.

Based on the opening price of Vistra Energy common stock on the Merger Date, the purchase price was approximately $2.3 
billion.  The purchase price allocation is substantially complete, but is dependent upon final valuation determinations, which may
materially change from our current estimates.  The preliminary values for property plant and equipment, identifiable intangible
assets and liabilities, goodwill, inventories, asset retirement obligations, contingent liabilities and deferred taxes represent our 
current best estimates of the fair value at the Merger Date.  We currently expect the final purchase price allocation will be completed 
no later than the first quarter of 2019 and goodwill will be allocated to the related reporting units at that time.

See Note 2 to the Financial Statements for a summary of the Merger transaction and business combination accounting.

Acquisition, Development and Disposition of Generation Facilities

Battery Energy Storage Projects — We have completed the construction of our first battery energy storage system.  In October 
2018, we were awarded a $1 million grant from the TCEQ for our battery energy storage system at Upton 2 solar facility.  The
grant is part of the Texas Emissions Reduction Plan.  The 10 MW lithium-ion energy storage system captures excess solar energy
produced during the day and releases the energy in late afternoon and early evening, when demand is highest.  The project became
operational on December 31, 2018.

In June 2018, we announced that we would enter into a 20-year resource adequacy contract with Pacific Gas and Electric 
Company (PG&E) to develop a 300 MW battery energy storage project at our Moss Landing Power Plant site in California.  PG&E 
filed its application with the California Public Utilities Commission (CPUC) in June 2018 and the CPUC approved the contract 
in November 2018.  We anticipate the battery storage project will enter commercial operations by the fourth quarter of 2020.

Upton 2 Solar Development — In May 2017, we acquired the rights to develop, construct and operate a utility scale solar 
photovoltaic  power  generation  facility  in  Upton  County,  Texas.   As  part  of  this  project,  we  entered  a  turnkey  engineering, 
procurement and construction agreement to construct the approximately 180 MW facility.  The facility began test operations in
March 2018 and commercial operations began in June 2018.

t

CCGT Plant Acquisition — In July 2017, La Frontera Holdings, LLC (La Frontera), an indirect wholly owned subsidiary of 
Vistra  Energy,  entered  into  an  asset  purchase  agreement  with  Odessa-Ector  Power  Partners,  L.P.,  an  indirect  wholly  owned 
subsidiary of Koch Ag & Energy Solutions, LLC (the Odessa Acquisition), to acquire a 1,054 MW CCGT natural gas-fueled 
generation plant (and other related assets and liabilities) located in Odessa, Texas (the Odessa Facility).  On August 1, 2017, the 
Odessa Acquisition  closed  and  La  Frontera  acquired  the  Odessa  Facility.    La  Frontera  paid  an  aggregate  purchase  price  of 
approximately $355 million, plus a five-year earn-out provision, to acquire the Odessa Facility.  The purchase price was funded
by cash on hand.  Subsequent to the acquisition, the earn-out provision has been accounted for as a derivative in our consolidated 
financial statements, and partial buybacks of the earn-out provision were settled in February and May 2018.

Retirement of Generation Plants — In August 2018, we filed a notice of suspension of operation with PJM and other mandatory
regulatory notifications related to the retirement of our 51 MW Northeastern waste coal facility in McAddo, Pennsylvania.  We 
decided to retire the facility due to its uneconomic operations and financial outlook.  Following the receipt of regulatory approvals,
the facility was retired in October 2018.

Two of our non-operated, jointly held power plants acquired in the Merger for which our proportional generation capacity

was 883 MW, were retired in May 2018.  These units were retired as previously scheduled.

44

In October 2017, Luminant announced plans to retire three power plants with a total installed nameplate generation capacity 
of approximately 4,167 MW and two lignite mines.  These power plants include the Monticello, Sandow 4, Sandow 5 and Big
Brown generation units.  Luminant decided to retire these units because they were projected to be uneconomic based on then
current market conditions and would have faced significant environmental costs associated with operating such units.  In the case
of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Companynn
and Alcoa agreed to an early settlement of a long-standing power and mining agreement.

As part of the retirement process, Luminant filed notices with ERCOT, which triggered a reliability review regarding such
proposed retirements.  In October and November 2017, ERCOT determined the units were not needed for reliability.  The Sandow
and Monticello units were retired in January 2018, and the Big Brown units were retired in February 2018.

During the year ended December 31, 2017, we recorded charges of approximately $206 million related to the retirements, 
including employee related severance costs, noncash charges for writing off materials inventory and a contract intangible asset
associated with the Big Brown plant and the acceleration of Luminant's mining reclamation obligations (see Note 23 to the Financial 
Statements).  In addition, we will continue the ongoing reclamation work at the plants' mines.

t

Termination and Settlement of Alcoa Contract — In October 2017, subsidiaries of Vistra Energy (Vistra Parties) entered into
a separation and settlement agreement (Settlement Agreement) with Alcoa Corporation and Alcoa USA Corp. (collectively, the 
Alcoa Parties).  Pursuant to the Settlement Agreement, the Vistra Parties and the Alcoa Parties agreed to early termination of a
series of agreements related to industrial operations near Rockdale, Texas, thereby ending their contractual relationship with respect 
to the power generation unit known as Sandow Unit 4 and the mine known as Three Oaks Mine.  The terminated agreements were
scheduled to terminate in 2038 absent the Settlement Agreement.  Among other things, the Alcoa Parties made a cash payment to
the Vistra Parties in the amount of approximately $238 million and transferred certain real property and related assets to the Vistra 
Parties, the Vistra Parties agreed to assume and be responsible for certain liabilities and asset retirement obligations related to
Sandow Unit 4 (including certain related common facilities), the related mine and other property transferred from the Alcoa Parties
to the Vistra Parties, and both parties released one another from any obligations and claims under the terminated agreements.  The
transactions under the Settlement Agreement were effective as of October 1, 2017.  See Note 8 to the Financial Statements.

rr

Dividend Program

In November 2018, we announced that the Board had adopted a dividend program pursuant to which we expect to initiate 
an annual dividend of approximately $0.50 per share, payable quarterly, beginning in the first quarter of 2019.  Each dividend 
under the program will be subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the
time of any such declaration including, but not limited to, prevailing market conditions, our results of operations, financial condition 
and liquidity and Delaware law.

On February 26, 2019, Vistra Energy announced that the Board had declared a dividend pursuant to which Vistra Energy 

would pay, to each holder of record as of March 15, 2019, a dividend of $0.125 per share, to be paid March 29, 2019.

Share Repurchase Program

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

In November 2018, we announced that the Board had authorized an incremental share repurchase program under which up 
to $1.25 billion of our outstanding stock may be purchased.  Through December 31, 2018, 12,073,091 shares of our common stock 
had been repurchased for $278 million (including related fees and expenses) at an average price per share of common stock of 
$22.99, and at December 31, 2018, $972 million was available for additional repurchases under the program.  On a cumulative
basis through February 25, 2019, 19,167,147 shares of our common stock had been repurchased for $451 million (including related
fees and expenses) at an average price per share of common stock of $23.52, and at February 25, 2019, $799 million was available
for additional repurchases under the program.  We intend to implement the program opportunistically from time to time over the 
next 12 months.

45

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

Debt Activity

We have a target to reduce leverage to approximately 2.5x net debt/EBITDA.  The following transactions reflect our intention
to simplify our capital structure and reduce interest expense.  We will continue to pursue opportunities to refinance our long-term 
debt and reduce interest expense.

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

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

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

Bond Repurchase Program — In November 2018, the Board authorized a bond repurchase program under which up to $200
million principal amount of outstanding Vistra Energy senior notes could be repurchased.  Through December 31, 2018, $119 
million aggregate principal amount of senior notes had been repurchased.

Accounts Receivable Securitization Program — In August 2018, TXU Energy Receivables Company LLC (RecCo), a wholly 
owned subsidiary of TXU Energy, and Vistra Energy entered into a $350 million accounts receivable financing facility (Receivables
Facility), currently scheduled to terminate in August 2019, with issuers of asset-backed commercial paper and commercial banks. 
Vistra Energy expects to have the opportunity to renew and/or extend the Receivables Facility upon its expiration subject to such 
terms and conditions as may be agreed upon by the parties thereto.  The Receivables Facility provides Vistra Energy with the
ability to borrow up to $350 million.  See Note 13 to the Financial Statements for details of the accounts receivable securitization 
program.

Issuance of Vistra Operations 5.500% Senior Notes Due 2026 — In August 2018, Vistra Operations issued and sold $1
billion aggregate principal amount of the 5.500% senior notes due 2026 in an offering to eligible purchasers under Rule 144A and 
Regulation S under the Securities Act of 1933, as amended.  The senior notes were sold pursuant to a purchase agreement by and 
among Vistra  Operations,  certain  direct  and  indirect  subsidiaries  of Vistra  Operations  and  Citigroup  Global  Markets  Inc.,  as
representative of the several initial purchasers.  Net proceeds from the sale of the senior notes totaling approximately $990 million,
together with cash on hand and cash received from the funding of the accounts receivable securitization program described above, 
were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the tender 
offers described below.

46

2018 Tender Offers and Consent Solicitations — In August 2018, Vistra Energy used the net proceeds from the issuance of 
the Vistra Operations 5.500% senior notes due 2026, proceeds from the accounts receivable securitization program and cash on 
hand to fund cash tender offers to purchase for cash $1.542 billion of senior notes assumed in the Merger.  In connection with the 
tender offers, Vistra Energy also commenced solicitations of consents from holders of the 7.375% senior notes due 2022, the 
7.625% senior notes due 2024, the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes 
due 2026 to amend certain provisions of the applicable indentures governing each series of senior notes and the registration rights 
agreement with respect to the 8.125% senior notes due 2026.  Vistra Energy received the requisite consents from the holders of 
the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes due 2026 and amended the 
indentures governing each series of the applicable senior notes to, among other things, eliminate substantially all of the restrictive
covenants and certain events of default.  In addition, Vistra Energy received the requisite consents from the holders of the 8.125%
senior notes due 2026 and amended the registration rights agreement with respect to the 8.125% senior notes due 2026 to remove,
among other things, the requirement that Vistra Energy commence an exchange offer to issue registered securities in exchange 
for the notes.

tt

Amendment to Vistra Operations Credit Facilities — In June 2018, the Credit Facilities Agreement was amended.  Among

other things, the amendment included the following updated terms:

•  Aggregate commitments under the Revolving Credit Facility were increased from $860 million to $2.5 billion.  The 
letter of credit sub-facility was also increased from $715 million to $2.3 billion.  The maturity date of the Revolving
Credit Facility was extended from August 4, 2021 to June 14, 2023.  Pricing terms for the Revolving Credit Facility 
were reduced from LIBOR plus an applicable margin of 2.25% to LIBOR plus an applicable margin of 1.75%.  Pricing 
terms for letters of credit issued under the Revolving Credit Facility were reduced from 2.25% to 1.75%.
Pricing terms for the Term Loan B-1 Facility were reduced from LIBOR plus an applicable margin of 2.50% to LIBOR 
plus an applicable margin of 2.00%.

• 

•  Borrowings under the new Term Loan B-3 Facility of $2.040 billion principal amount were used to repay borrowings 
under the credit agreement that Vistra Energy assumed from Dynegy in connection with the Merger.  Amounts borrowed 
under the Term Loan B-3 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%, and the 
maturity date of the facility is December 31, 2025.

•  Borrowings under the Term Loan C Facility of $500 million were repaid using $500 million of cash from collateral 

accounts used to backstop letters of credit.

See Note 14 to the Financial Statements for details of the Vistra Operations Credit Facilities.

Redemption of Debt — In May 2018, $850 million aggregate principal amount of outstanding 6.75% Senior Notes due 2019
was redeemed at a redemption price of 101.688% of the aggregate principal amount, plus accrued and unpaid interest to but not 
including the date of redemption (see Note 14).

t

Environmental Matters

See Note 15 to Financial Statements for a discussion of greenhouse gas emissions, the Cross-State Air Pollution Rule, regional

haze, state implementation plan and other recent EPA actions as well as related litigation.

47

Capacity Markets

PJM — Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for 

M
each planning year:

RTO zone (a)
ComEd zone
MAAC zone
EMAAC zone
ATSI zone
PPL zone

2018-2019

2019-2020

2020-2021

2021-2022

Base

CP

Base

CP

CP

CP

(price per MW-day)

$

$

149.98
200.21
149.98
210.63
149.88
75.00

$

164.77
215.00
164.77
225.42
164.77
164.77

$

80.00
182.77
80.00
99.77
80.00
80.00

$

100.00
202.77
100.00
119.77
100.00
100.00

$

88.32
188.12
86.04
187.87
76.53
86.04

140.00
195.55
140.00
165.73
171.33
140.00

____________
(a)  Planning Year 2020-2021 includes Duke Energy Ohio Kentucky (DEOK) zone which cleared at $130.00 per MW-day.  RTO

Zone excluding DEOK Zone was $76.53 per MW-day.

Our capacity sales, net of purchases, aggregated by planning year and capacity type through planning year 2020-2021, are

as follows:

Base auction capacity sold, net (MW)
CP auction capacity sold, net (MW)
Bilateral capacity sold, net (MW)

Total segment capacity sold, net (MW)

Average price per MW-day

2018-2019

2019-2020

2020-2021

2021-2022

1,420
7,771
285
9,476

893
8,144
200
9,237

—
8,642
200
8,842

—
9,053
200
9,253

$

186.40

$

135.56

$

129.30

$

159.22

NYISO —  The  most  recent  seasonal  auction  results  for  NYISO's  Rest-of-State  zones,  in  which  the  capacity  for  our 

Independence plant clears, are as follows for each planning period:

Price per kW-month

Summer 
2018

$

1.75

$

Winter 
2018 - 2019
0.35

Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through

bilateral trades.  Our capacity sales, aggregated by season through summer 2021, are as follows:

Auction capacity sold (MW)
Bilateral capacity sold (MW)
Total capacity sold (MW)
Average price per kW-month

Winter 
2018 - 2019
88
989
1,077
1.37

$

$

Summer 
2019

—
540
540
2.71

Winter 
2019 - 2020
—
210
210
2.57

$

$

Summer 
2020

—
75
75
3.15

Winter 
2020 - 2021
—
38
38
3.13

$

$

Summer 
2021

—
20
20
3.08

48

ISO-NE — The most recent FCA results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows

E
for each planning year:

Price per kW-month

2018-2019

2019-2020

2020-2021

2021-2022

2022-2023

$

9.55

$

7.03

$

5.30

$

4.63

$

3.80

Performance incentive rules went into effect for planning year 2018-2019, increasing capacity payments for those resources 
that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required 
level.  We continue to market and pursue longer term multi-year capacity transactions that extend planning year 2021-2022.

Auction capacity sold (MW)
Bilateral capacity sold (MW)
Total capacity sold (MW)
Average price per kW-month

2018-2018

2019-2020

2020-2021

2021-2022

2022-2023

3,108
239
3,347
9.80

$

3,161
75
3,236
7.02

$

3,079
150
3,229
5.40

$

2,592
170
2,762
4.80

$

3,137
95
3,232
3.92

$

MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for 

each planning year:

Price per MW-day

2018-2019

$

10.00

MISO capacity sales through planning year 2020-2021 are as follows:

Bilateral capacity sold in MISO (MW)
Base auction capacity sold in PJM (MW)
CP auction capacity sold in PJM (MW)

Total MISO segment capacity sold (MW)

2,533
227
835
3,595

2,047
260
356
2,663

1,663
—
444
2,107

Average price per kW-month

$

3.70

$

3.62

$

3.81

$

667
—
798
1,465

4.22

2018-2019

2019-2020

2020-2021

2021-2022

CAISO — Our capacity sales, aggregated by calendar year for 2019 through 2021 for Moss Landing, are as follows:

Bilateral capacity sold (Avg MW)

2019

2020

2021

890

—

—

49

Key Operational Risks and Challenges

Following is a discussion of key operational risks and challenges facing management and the initiatives currently underway
to manage such challenges.  These matters involve risks that could have a material effect on our results of operations, liquidity or 
financial condition.

Natural Gas Price and Market Heat Rate Exposure

The  price  of  power  is  typically  set  by  natural  gas-fueled  generation  facilities,  with  wholesale  prices  generally  tracking 
increases or decreases in the price of natural gas.  In recent years, natural gas supply has outpaced demand primarily as a result 
of development and expansion of hydraulic fracturing in natural gas extraction; the supply/demand imbalance has resulted in 
historically low natural gas prices, and such prices have historically been volatile.  The table below shows the general decline in 
forward natural gas prices over the last several years (amounts are per MMBtu.)

Decline of Settled and Forward Natural Gas Prices Since 2008

)
a
(

s
e
c
i
r
P
t
e
k
r
a

M

$9.00

$8.00

$7.00

$6.00

$5.00

$4.00

$3.00

$2.00

$1.00

$0.00

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Period Ending December 31,

Settled

Three Years Forward

________________
(a)  Settled prices represent the average of NYMEX Henry Hub monthly settled prices of financial contracts for the year ending 
on the date presented.  Forward prices represent the three-year average of NYMEX Henry Hub monthly forward prices at 
the date presented.  Three-year forward prices are presented as such period is generally deemed to be a liquid period.

50

 
 
In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost 
of generating power at our nuclear-, lignite- and coal-fueled facilities, which represent a substantial amount of our generation
capacity.  Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets increase or decrease 
in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on our operating margins from
changes in wholesale electricity prices.  A persistent decline in the price of natural gas, and the corresponding decline in the price 
of power, would likely have a material adverse effect on our results of operations, liquidity and financial condition, predominantly 
related  to  the  production  of  power  generation  volumes  in  excess  of  the  volumes  utilized  to  service  our  retail  customer  load 
requirements.

The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate.  Market 
heat rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of the marginal 
supplier (generally natural gas-fueled generation facilities) in generating electricity.  Our market heat rate exposure is impacted 
by  changes  in  the  availability  of  generation  resources,  such  as  additions  and  retirements  of  generation  facilities,  and  mix  of 
generation assets.  For example, increasing renewable (wind and solar) generation capacity generally depresses market heat rates. 
Our heat rate exposure is also impacted by the potential economic backdown of our generation assets.  Decreases in market heat 
rates decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity
prices, and vice versa.  However, even though market heat rates have generally increased over the past several years, wholesale
electricity prices have declined due to the greater effect of falling natural gas prices.

a

As a result of our exposure to the variability of natural gas prices and market heat rates, retail sales and hedging activities

are critical to our operating results and maintaining consistent cash flow levels.

Our integrated power generation and retail electricity business provides us opportunities to hedge our generation position 
utilizing retail electricity markets as a sales channel.  In addition, our approach to managing electricity price risk focuses on the
following:

• 

• 
• 

• 

employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-
related contracts intended to partially hedge gross margins;
continuing focus on cost management to better withstand gross margin volatility;
following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the magnitude
and costs of commodity price, liquidity risk and retail demand variability, and
improving retail customer service to attract and retain high-value customers.

We  have  engaged  in  natural  gas  hedging  activities  to  mitigate  the  risk  of  lower  wholesale  electricity  prices  that  have 
corresponded to declines in natural gas prices.  While current and forward natural gas prices are currently depressed, we continue 
to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and 
retail electricity sales.

Taking together forward wholesale, retail electricity sales and other retail customer considerations and all other hedging 
positions in ERCOT, at December 31, 2018, we had effectively hedged an estimated 99% and 91% of the natural gas price exposure 
related to our overall business for 2019 and 2020, respectively.  These percentages assume conversion of generation positions
based on market heat rates and an estimate of natural gas generally being on the margin 70% to 90% of the time in the ERCOT 
market.   Additionally,  taking  into  consideration  our  overall  heat  rate  exposure  and  related  hedging  positions  in  ERCOT  at 
December 31, 2018, we had effectively hedged 88% and 42% of the heat rate exposure to our overall business for 2019 and 2020, 
respectively.  We make the distinction between natural gas price exposure and heat rate exposure for the ERCOT market because 
of the high percentage of time natural gas is on the margin and the availability of traded products in ERCOT to hedge heat rate
directly.  Generation volumes hedged in PJM, NYISO, ISO-NE, MISO and CAISO at December 31, 2018 were as follows:

PJM
NYISO/ISO-NE
MISO/CAISO

2019

2020

87%
81%
65%

57%
29%
35%

51

The following sensitivity table provides approximate estimates of the potential impact of movements in natural gas prices 
and market heat rates on realized pretax earnings (in millions) taking into account the hedge positions noted in the paragraph above
for the periods presented.  The estimates related to price sensitivity are based on our expected generation and retail positions,
related hedges and forward prices as of December 31, 2018.

ERCOT:

$0.50/MMBtu increase in natural gas price (b)
$0.50/MMBtu decrease in natural gas price (b)
1.0/MMBtu/MWh increase in market heat rate (c)
1.0/MMBtu/MWh decrease in market heat rate (c)

PJM:

$0.50/MMBtu increase in natural gas price (d)
$0.50/MMBtu decrease in natural gas price (d)
1.0/MMBtu/MWh increase in market heat rate (e)
1.0/MMBtu/MWh decrease in market heat rate (e)

NYISO/ISO-NE:

$0.50/MMBtu increase in natural gas price (d)
$0.50/MMBtu decrease in natural gas price (d)
1.0/MMBtu/MWh increase in market heat rate (f)
1.0/MMBtu/MWh decrease in market heat rate (f)

MISO/CAISO:

$0.50/MMBtu increase in natural gas price (d)
$0.50/MMBtu decrease in natural gas price (d)
1.0/MMBtu/MWh increase in market heat rate (g)
1.0/MMBtu/MWh decrease in market heat rate (g)

Balance 2019 (a)

2020

$               ~115
$               ~50
$               ~(35) $               ~(100)
$               ~60
$               ~165
$               ~(45) $               ~(150)

$               ~32
$               ~93
$                 ~(22) $               ~(72)
$               ~71
$               ~33
$               ~(26) $               ~(68)

$                 ~11 $               ~66
$                   ~(5) $               ~(54)
$               ~23
$               ~62
$               ~(11) $                  ~(50)

$               ~85
$               ~145
$                  ~(68) $               ~(116)
$               ~73
$               ~47
$               ~(65)
$               ~(42)

___________
(a)  Balance of 2019 is from February 1, 2019 through December 31, 2019.
(b)  Based on Houston Ship Channel natural gas prices at December 31, 2018.
(c)  Based on ERCOT North Hub around-the-clock heat rates at December 31, 2018.
(d)  Based on NYMEX natural gas prices at December 31, 2018.
(e)  Based on AEP Dayton Hub, Northern Illinois Hub and PJM West Hub around-the-clock heat rates at December 31, 2018.
(f)  Based on Massachusetts Hub and NYISO Zone C around-the-clock heat rates at December 31, 2018.
(g)  Based on Indiana Hub and NP15 around-the-clock heat rates at December 31, 2018.

Competitive Retail Markets and Customer Retention

Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch retail electricity providers
for various reasons.  Based on numbers of meters, our total retail customer counts increased 2% in 2018, increased slightly in
2017 and declined approximately 1% in 2016.  Based upon December 31, 2018 results discussed below in Results of Operations,
a 1% decline in retail customers would result in a decline in annual revenues of approximately $55 million.  In responding to thet
competitive landscape in the ERCOT market, we have attempted to reduce overall customer losses by focusing on the following 
key initiatives:

•  Maintaining competitive pricing initiatives on residential service plans;
•  Actively competing for new customers in areas open to competition within ERCOT, while continuing to strive to enhance 
the experience of our existing customers; we are focused on continuing to implement initiatives that deliver world-class
customer service and improve the overall customer experience;

•  Establishing and leveraging our TXU EnergyTM brand in the sale of electricity to residential and commercial customers, 
as the most innovative retailer in the ERCOT market by continuing to develop tailored product offerings to meet customer 
needs, and

52

• 

Focusing  market  initiatives  largely  on  programs  targeted  at  retaining  the  existing  highest-value  customers  and  to
recapturing customers who have switched REPs, including maintaining and continuously refining a disciplined contracting
and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts 
and to more effectively deploy our direct-sales force; tactical programs we have initiated include improved customer 
service, aided by an enhanced customer management system, new product price/service offerings and a multichannel 
approach for the small business market.

Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate 
generation capacity of 1,150 MW.  As of December 31, 2018, these units represented approximately 6% of our total generation
capacity.  The nuclear generation units represent our lowest marginal cost source of electricity.  Assuming both nuclear generation 
units experienced an outage at the same time, the unfavorable impact to pretax earnings is estimated (based upon forward electricity 
market prices for 2019 at December 31, 2018) to be approximately $1 million per day before consideration of any costs to repair
the cause of such outages or receipt of any insurance proceeds.  Also see discussion of nuclear facilities insurance in Note 15 to 
the Financial Statements.

The  inherent  complexities  and  related  regulations  associated  with  operating  nuclear  generation  facilities  result  in 
environmental, regulatory and financial risks.  The operation of nuclear generation facilities is subject to continuing review and 
regulation by the NRC, covering, among other things, operations, maintenance, emergency planning, security, and environmental 
and safety protection.  The NRC may implement changes in regulations that result in increased capital or operating costs and may aa
require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing
regulations and the provisions of the Atomic Energy Act.  In addition, an unplanned outage at another nuclear generation facility
could result in the NRC taking action to shut down our Comanche Peak units as a precautionary measure.

We participate in industry groups and with regulators to keep current on the latest developments in nuclear safety, operation 
and maintenance and on emerging threats and mitigating techniques.  These groups include, but are not limited to, the NRC, the
Institute of Nuclear Power Operations (INPO) and the Nuclear Energy Institute (NEI).  We also apply the knowledge gained 
through our continuing investment in technology, processes and services to improve our operations and to detect, mitigate and 
protect our nuclear generation assets.  Management continues to focus on the safe, reliable and efficient operations at the facility.

Cyber/Data Security and Infrastructure Protection Risk

A breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business 
operations and affect our ability to control our generation assets, access retail customer information and limit communication with 
third parties.  Any loss of confidential or proprietary data through a breach could materially affect our reputation, including our 
TXU EnergyTM, Dynegy Energy Services and Homefield Energy brands, expose the company to legal claims or impair our ability
to execute on business strategies.

We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques.  These
groups include, but are not limited to, the U.S. Cyber Emergency Response Team, the National Electric Sector Cyber Security
Organization, the NRC and NERC.

While the company has not experienced a cyber/data event causing any material operational, reputational or financial impact,
we recognize the growing threat within the general market place and our industry, and are proactively making strategic investments
in our perimeter and internal defenses, cyber/data security operations center and regulatory compliance activities.  We also apply
the knowledge gained through industry and government organizations to continuously improve our technology, processes and 
services to detect, mitigate and protect our cyber and data assets.

Seasonality

The demand for and market prices of electricity and natural gas are affected by weather.  As a result, our operating results 
may fluctuate on a seasonal basis.  Typically, demand for and the price of electricity is higher in the summer and winter seasons,
when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter.  More 
severe weather conditions such as heat waves or extreme winter weather may make such fluctuations more pronounced.  However,
not all regions of the U.S. typically experience extreme weather conditions at the same time, so Vistra Energy is typically not
exposed to the effects of extreme weather in all parts of its business at once.  The pattern of this fluctuation may change depending
on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.

53

Application of Critical Accounting Policies

Our significant accounting policies are discussed in Note 1 to the Financial Statements.  We follow accounting principles
generally accepted in the U.S.  Application of these accounting policies in the preparation of our consolidated financial statements
requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at 
the balance sheet dates and revenues and expenses during the periods covered.  The following is a summary of certain critical 
accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using 
different assumptions or estimation methodologies.

Purchase Accounting

On the Merger Date, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation.  

The Merger is being accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets
acquired and liabilities assumed recorded at their estimated fair values on the Merger Date.  Vistra Energy is the acquirer for both 
federal tax and accounting purposes.  The combined results of operations are reported in our consolidated financial statements 
beginning as of the Merger Date.  See Note 2 to the Financial Statements. 

r

During the measurement period, which is up to one year from the Merger date, we record adjustments to the initial estimates 
in the reporting period in which the adjustment amounts are determined based on facts and circumstances that existed as of the 
acquisition date.  We expect to finalize our purchase price allocation in the quarter ended March 31, 2019.  Upon the conclusion 
of the measurement period, any subsequent adjustments will be recorded to earnings.  Transaction costs have been expensed as
incurred.

The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant 
and equipment and executory contracts, primarily long-term service agreements for maintenance of power plants and a unit-
specific power sales agreement.  The fair value of each power plant was estimated using a combination of an income approach 
and a market approach.  The income approach is the present value of future cash flows over the life of each power plant that are
based on management’s estimates of revenues and operating expenses, and appropriate discount rates.  The estimate of long term 
prices of electricity and natural gas at each plant location that was used in developing forecasted revenues for the income approach 
was especially subjective, because as of the Merger Date, limited market information about future prices beyond the year 2022 
was available.  The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the relevant
market, with adjustments relating to any differences between the assets and locations.  The determination of deferred tax assets
was complex as it required assessing income tax rules and regulations and proposed regulations that impose limitations on the 
future use of acquired net operating losses and other limitations on deductions.

Accounting in Reorganization and Fresh-Start Reporting

The consolidated financial statements of our Predecessor reflect the application of ASC 852.  During the Chapter 11 Cases,
the Debtors, including our Predecessor and its subsidiaries, 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.  ASC 852 applies to entities
that have filed a petition for bankruptcy under Chapter 11 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.  Expenses and income directly associated with the 
Chapter 11 Cases are reported separately in the statements of consolidated income (loss) as reorganization items.  Reorganization 
items also include adjustments to reflect the carrying value of liabilities subject to compromise (LSTC) at their estimated allowed 
claim amounts, as such adjustments are determined.  See Note 5 to the Financial Statements.

As of the Effective Date, Vistra Energy applied fresh-start reporting under the applicable provisions of ASC 852.  Fresh-
start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring 
from the consolidated financial statements of the entity that emerges from restructuring, (2) assigning the reorganized value of 
the successor entity by measuring all assets and liabilities of the successor entity at fair value, and (3) selecting accounting policies
for the successor entity.  The effects from emerging from bankruptcy, including the extinguishment of liabilities, as well as the 
fresh start reporting adjustments are reported in the Predecessor's statement of consolidated income (loss).  The consolidated 
financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements
of our Predecessor for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the 
carrying values of assets or amounts of liabilities, nor any differences in accounting policies that were a consequence of the Plan 
of Reorganization or the related application of fresh-start reporting.  See Note 6 to the Financial Statements.

t

tt

54

Derivative Instruments and Mark-to-Market Accounting

We  enter  into  contracts  for  the  purchase  and  sale  of  energy-related  commodities,  and  also  enter  into  other  derivative 
instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks.  Under 
accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market 
accounting,  and  the  determination  of  market  values  for  these  instruments  is  based  on  numerous  assumptions  and  estimation
techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as 
market prices change.  Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income
with an offset to derivative assets and liabilities.  The availability of quoted market prices in energy markets is dependent on the
type  of  commodity  (e.g.,  natural  gas,  electricity,  etc.),  time  period  specified  and  delivery  point.    In  computing  fair  value  for 
derivatives, each forward pricing curve is separated into liquid and illiquid periods.  The liquid period varies by delivery point 
and commodity.  Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity.  For 
illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account 
available market information and other inputs that might not be readily observable in the market.  We estimate fair value as 
described in Note 17 to the Financial Statements.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections 
and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net 
income and thus reduce the volatility of net income that can result from fluctuations in fair values.  Normal purchases and sales
are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal 
course of business and are not subject to mark-to-market accounting if the normal purchase or sale election is made.  Accounting 
standards also permit an entity to designate certain qualifying derivative contracts in a hedge accounting relationship, whereby
changes in fair value are not recognized immediately in earnings.  Vistra Energy does not have derivative instruments with hedge
accounting designations.

We  report  derivative  assets  and  liabilities  in  the  consolidated  balance  sheets  without  taking  into  consideration  netting
arrangements that 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
CME  transactions  that,  beginning  in  January  2017,  are  legally  characterized  as  settlement  of  derivative  contracts  rather  than 
collateral.

See Note 18 to the Financial Statements for further discussion regarding derivative instruments.

Accounting for Income Taxes

Subsequent to the Effective Date, Vistra Energy files a United States federal income tax return that includes the results of 
its consolidated subsidiaries.  Vistra Energy is the corporate parent of the Vistra Energy consolidated group.  Pursuant to applicable
United States Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have
joint and several liability for the taxes of such group.

Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and 
judgments.  Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates
and judgments of the timing and probability of recognition of income and deductions by taxing authorities.  In assessing the
likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable 
income.  Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes 
in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed 
tax  returns  by  taxing  authorities.    Income  tax  returns  are  regularly  subject  to  examination  by  applicable  tax  authorities.    In 
management's opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects
future taxes that may be owed as a result of any examination.

Our deferred tax assets were significantly impacted by the TCJA, 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 during the year ended 
December 31, 2017.

See Notes 1 and 9 to the Financial Statements for discussion of income tax matters.

55

Accounting for Tax Receivable Agreement

On the Effective Date, we entered into a tax receivable agreement (the TRA) with a transfer agent.  Pursuant to the TRA,
we issued beneficial interests in the rights to receive payments under the TRA (the TRA Rights) to the first lien creditors of our 
Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to receive such TRA Rights 
under the Plan of Reorganization.  Vistra Energy reflected the obligation associated with TRA Rights at fair value in the amount nn
of $574 million as of the Emergence Date related to these future payment obligations.  As of December 31, 2018, the TRA obligation
has been adjusted to $420 million.  During the year ended December 31, 2018, we recorded an increase to the carrying value of 
the TRA obligation totaling $14 million.  The largest driver in the increase to the TRA obligation carrying value primarily resulted 
from in the timing of estimated payments and new multistate tax impacts resulting from the Merger, which increased the total 
expected undiscounted payments under the TRA from $1.2 billion to $1.4 billion.  The TRA obligation value is the discounted 
amount of estimated payments to be made each year under the TRA, based on certain assumptions, including but not limited to:

• 

• 

the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo Preferred 
Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up among the 
assets subject thereto;
the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most 
of such assets;

•  a blended federal/state corporate income tax rate in all future years of 23%;
• 
• 

future taxable income by year for future years;
the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of 
(i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as 
a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us 
as a result of payments under the TRA in the tax year in which such deductions arise;

•  a discount rate of 15%, which represented our view at the Emergence Date of the rate that a market participant would 
use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence,
and

•  additional  states  that  Vistra  Energy  now  operates  in,  the  relevant  tax  rates  of  those  states  and  how  income  will  be

apportioned to those states.

We recognize accretion expense over the life of the TRA Rights liability as the present value of the liability is accreted up 
over the life of the liability.  This noncash accretion expense is reported in the statements of consolidated income (loss) as Impacts 
of Tax Receivable Agreement.  Further, there may be significant changes, which may be material, to the estimate of the related 
liability due to various reasons including changes in corporate tax law, changes in estimates of the amount or timing of future
taxable income of Vistra Energy and its subsidiaries and other items.  Changes in those estimates are recognized as adjustments
to the related TRA Rights liability, with offsetting impacts recorded in the statements of consolidated income (loss) as Impacts of 
Tax Receivable Agreement.  See Note 10 to the Financial Statements.

Asset Retirement Obligations (ARO)

As  part  of  fresh  start  reporting,  new  fair  values  were  established  for  all AROs  for  the  Successor.   As  part  of  business
combination accounting, new fair values were established for all AROs assumed in the Merger.  A liability is initially recorded at d
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.  Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and 
related asset as information becomes available.  Changes in estimates related to assets that have been retired or for which capitalized 
costs are not recoverable are reflected in the statement of consolidated income (loss).

During the year ended December 31, 2017, we recorded additional ARO obligations totaling $112 million primarily reflecting 
the acceleration of ARO obligations due to the retirements of our Monticello, Sandow and Big Brown plants.  In addition, we 
recorded additional ARO obligations totaling $62 million as part of acquiring certain real property through the Alcoa contract 
settlement.

See Note 23 to the Financial Statements for additional discussion of ARO obligations.

56

Impairment of Goodwill and Other Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting 
standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their 
carrying amount may not be recoverable.  For our generation assets, possible indications include an expectation of continuing 
long-term declines in natural gas prices and/or market heat rates or an expectation that "more likely than not" a generation asset 
will be sold or otherwise disposed of significantly before the end of its estimated useful life.  The determination of the existence
of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates
in forecasting future results and cash flows related to an asset or group of assets.  Further, the unique nature of our property, plant 
and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying 
production or output rates, requires the use of significant judgments in determining the existence of impairment indications and 
the grouping of assets for impairment testing.  We generally utilize an income approach measurement to derive fair values for our 
long-lived generation assets.  The income approach involves estimates of future performance that reflect assumptions regarding,
among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation 
plant performance, forecasted capital expenditures and forecasted fuel prices.  Any significant change to one or more of these
factors can have a material impact on the fair value measurement of our long-lived assets.  Additional material impairments related 
to our generation facilities may occur in the future if forward wholesale electricity prices decline in the markets in which we
operate in or if additional environmental regulations increase the cost of producing electricity at our generation facilities.

a

Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the TXU EnergyTM, 4Change
EnergyTM, Homefield and Dynegy Energy Services brands, are required to be tested for impairment at least annually (as of the
Effective Date, we have selected October 1 as our annual test date) or whenever events or changes in circumstances indicate an 
impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in
values of comparable public companies in our industry.  Accounting standards allow a company to qualitatively assess if the 
carrying value of a reporting unit with goodwill is more likely than not less than the fair value of that reporting unit.  If the entity
determines the carrying value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for 
impairment is required.  On the most recent goodwill testing date, we applied qualitative factors and determined that it was more 
likely than not that the fair value of our ERCOT Retail reporting unit exceeded its carrying value at October 1, 2018.  Significant 
qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition, 
interest rates and changes in reporting unit book value.

t

Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2018, $1.907 billion of 
our goodwill was allocated to our ERCOT Retail reporting unit and $161 million arose in connection with the Merger and is 
recorded at the corporate and other level non-segment operations pending completion of the purchase price allocation in the first 
quarter of 2019, at which time goodwill will be allocated to reporting units.  Goodwill impairment testing is performed at the
reporting unit level.  Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds
its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair 
values of the reporting unit's assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant 
implied goodwill amount is then compared to the recorded goodwill amount.  Any excess of the recorded goodwill amount over 
the implied goodwill amount is written off as an impairment charge.

The determination of enterprise value involves a number of assumptions and estimates.  We use a combination of fair value 
measurements  to  estimate  enterprise  values  of  our  reporting  units  including:  internal  discounted  cash  flow  analyses  (income 
approach), and comparable publicly traded company values (market approach).  The income approach involves estimates of future
performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates,
the effects of environmental rules, generation plant performance, forecasted capital expenditures and retail sales volume trends,
as well as determination of a terminal value.  Another key variable in the income approach is the discount rate, or weighted average 
cost of capital, applied to the forecasted cash flows.  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.  The market approach involves using trading 
multiples of EBITDA of those selected publicly traded companies to derive appropriate multiples to apply to the EBITDA of our 
reporting units.  Critical judgments include the selection of publicly traded comparable companies and the weighting of the value 
metrics in developing the best estimate of enterprise value.

57

RESULTS OF OPERATIONS

Vistra Energy Consolidated Financial Results — Successor Years Ended December 31, 2018 and 2017 and the period from 
October 3, 2016 through December 31, 2016

Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Impairment of long-lived assets

Operating income

Other income
Other deductions
Interest expense and related charges
Impacts of Tax Receivable Agreement
Equity in earnings of unconsolidated investment

Income before income taxes

Income tax (expense) benefit

Net income (loss)

Successor

Year Ended December 31,

2018

2017

Favorable
(Unfavorable) 
$ Change

$

$

$

9,144
(5,036)
(1,297)
(1,394)
(926)
—
491
47
(5)
(572)
(79)
17
(101)
45
(56) $

$

5,430
(2,935)
(973)
(699)
(600)
(25)
198
37
(5)
(193)
213
—
250
(504)
(254) $

3,714
(2,101)
(324)
(695)
(326)
25
293
10
—
(379)
(292)
17
(351)
549
198

Period from
October 3, 2016 
through 
December 31, 2016
1,191
$
(720)
(208)
(216)
(208)
—
(161)
10
—
(60)
(22)
—
(233)
70
(163)

$

Operating revenues
Fuel, purchased power
costs and delivery fees
Operating costs
Depreciation and
amortization
Selling, general and
administrative expenses

Operating income (loss)

Other income
Other deductions
Interest expense and
related charges
Impacts of Tax Receivable
Agreement
Equity in earnings of
unconsolidated investment
Income (loss) before

income taxes
Income tax benefit

Net income (loss)

$

Retail

$

5,597

ERCOT
2,634
$

PJM
1,725

$

Successor

Year Ended December 31, 2018

NY/NE

MISO

Asset
Closure

Eliminations
/ Corporate
and Other

$

817

$

720

$

50

$

(2,399) $

Vistra 
Energy
Consolidated
9,144

(4,126)
(39)

(1,521)
(677)

(917)
(243)

(485)
(74)

(420)
(202)

(318)

(416)

(413)

(152)

(424)
690
29
—

(7)

—

—

(90)
(70)
34
(7)

(12)

—

—

(52)
100
1
—

(8)

—

7

712
—
712

$

(55)
—
(55) $

100
—
100

$

(36)
70
—
—

(2)

—

11

79
—
79

$

(9)

(53)
36
—
—

(1)

—

—

35
—
35

58

(40)
(43)

—

(17)
(50)
2
(1)

—

—

—

2,473
(19)

(5,036)
(1,297)

(86)

(1,394)

(254)
(285)
(19)
3

(542)

(79)

(1)

(926)
491
47
(5)

(572)

(79)

17

(101)
45
(56)

(49)
—
(49) $

(923)
45
(878) $

$

Year Ended December 31, 2017

Asset
Closure

Eliminations
/ Corporate
and Other

Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Impairment of long-lived assets

Operating income (loss)

Other income
Other deductions
Interest expense and related charges
Impacts of Tax Receivable Agreement
Income (loss) before income taxes
Income tax expense
Net income (loss)

Retail

4,058
(2,733)
(14)
(430)
(420)
—
461
34
—
—
—
495
—
495

$

$

$

ERCOT
1,794
$
(981)
(578)
(229)
(124)
—
(118)
24
(3)
(21)
—
(118)
—
(118) $

$

$

964
(607)
(380)
(1)
(19)
(25)
(68)
6
(1)
—
—
(63)
—
(63) $

Vistra 
Energy
Consolidated
5,430
(2,935)
(973)
(699)
(600)
(25)
198
37
(5)
(193)
213
250
(504)
(254)

(1,386) $
1,386
(1)
(39)
(37)
—
(77)
(27)
(1)
(172)
213
(64)
(504)
(568) $

We believe 2018 was a very successful year for Vistra Energy.  We completed the transformational Merger with Dynegy in
April.  We reduced post-acquisition consolidated debt by approximately $1.7 billion and refinanced an additional approximately
$11 billion of debt and revolving credit commitments at lower interest rates and extended maturities.  We completed construction
of the Upton 2 solar project and our first battery storage facility located at the Upton 2 site.  In addition, we were awarded a contract 
to develop the largest battery storage facility in North America.  In 2018, we also executed a balanced capital allocation plan, 
returning approximately $762 million to stockholders via share repurchases.  For the year ended December 31, 2018, net loss
includes $380 million in unrealized mark-to-market losses on commodity risk management activity in 2018 resulting from higher 
forward  power  prices,  principally  driven  by  higher  market  heat  rates.    Our  operating  segments  delivered  strong  operating 
performance with a disciplined focus on cost management, while generating and selling electricity in a safe and reliable manner.rr

Consolidated results increased $198 million to net loss of $56 million in the year ended December 31, 2018 compared to
the year ended December 31, 2017.  The change in results was driven by additional operations acquired in the Merger, increased 
prices and volumes in the ERCOT segment, favorable volumes in the Retail segment, and the impact of the Comanche Peak outage 
in  2017  and  related  insurance  proceeds,  partially  offset  by  increased  unrealized  mark-to-market  losses  on  commodity  risk 
management activity, one-time Merger-related expenses including severance and transaction fees and the first quarter of 2018
plant retirements.

Interest expense and related charges increased $379 million to $572 million in the year ended December 31, 2018 compared 
to the year ended December 31, 2017 and reflected a $324 million increase in interest expense incurred reflecting long-term debt 
assumed  in  the  Merger,  $34  million  change  in  unrealized  mark-to-market  gains/losses  on  interest  rate  swaps  and  a  debt 
extinguishment loss of $27 million in 2018.  See Note 11 to the Financial Statements.

For the year ended December 31, 2018, the Impacts of the Tax Receivable Agreement totaled expense of $79 million and 
reflected a loss due to changes in the estimated amount and timing of TRA payments totaling $14 million and accretion expense 
totaling $65 million.  For the year ended December 31, 2017, the Impacts of the Tax Receivable Agreement totaled income of 
$213 million and reflected a gain due to changes in the estimated timing of TRA payments totaling $295 million, partially offset 
by accretion expense totaling $82 million.  See Note 10 to the Financial Statements for discussion of the impacts of the Tax
Receivable Agreement Obligation.

For the year ended December 31, 2018, income tax benefit totaled $45 million and the effective tax rate was 44.6%.  For 
the year ended December 31, 2017, income tax expense totaled $504 million.  The effective tax rate in 2017 of 201.6% was higher
than the U.S. Federal Statutory rate of 35% primarily due to a $451 million reduction of deferred tax assets related to the decrease
in the corporate rate in the TCJA, partially offset by $80 million of tax impacts related to nondeductible TRA accretion.  See Note 
9 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

59

Period from October 3, 2016 through December 31, 2016

Successor

Asset
Closure

Eliminations
/ Corporate
and Other

Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses

Operating income (loss)

Other income
Interest expense and related charges
Impacts of Tax Receivable Agreement
Income (loss) before income taxes

Income tax benefit

Net income (loss)

Retail

912
(515)
(3)
(153)
(130)
111
3
—
—
114
—
114

$

$

$

ERCOT
212
$
(214)
(151)
(53)
(65)
(271)
2
1
—
(268) $
—
(268) $

$

$

238
(162)
(54)
—
(6)
16
1
—
—
17
—
17

$

$

Vistra 
Energy
Consolidated
1,191
(720)
(208)
(216)
(208)
(161)
10
(60)
(22)
(233)
70
(163)

(171) $
171
—
(10)
(7)
(17)
4
(61)
(22)
(96)
70
(26) $

Consolidated net loss totaled $163 million for the period from October 3, 2016 through December 31, 2016.  Results were 

primarily driven by:

•  Retail segment net income of $114 million for the period, which was primarily driven by favorable profit margins, 

including $113 million of unrealized gains in purchased power costs on positions with the ERCOT segment.

•  ERCOT segment net loss of $268 million for the period, which was primarily driven by unrealized mark-to-market 
losses on commodity risk management activities totaling $273 million for the period (including $113 million of unrealized 
losses  on  positions  with  the  Retail  segment  and  $22  million  of  unrealized  gains  on  hedging  activities  for  fuel  and 
purchased power costs).  The unrealized losses were driven by increases in forward natural gas prices during the period.

Interest expense and related charges totaled $60 million and reflected $51 million of interest expense incurred and $11 million

of unrealized mark-to-market losses on interest rate swaps (see Note 11 to the Financial Statements).

Impacts of the Tax Receivable Agreement were a loss of $22 million, which reflected accretion expense during the period. 

See Note 10 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement obligation.

Income tax benefit totaled $70 million.  The effective tax rate was 30.0%.  See Note 9 to the Financial Statements for 

reconciliation of this effective rate to the U.S. federal statutory rate.

Discussion of Adjusted EBITDA

Non-GAAP Measures — In analyzing and planning for our business, we supplement our use of GAAP financial measures 
with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures.  These non-GAAP 
financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the
accompanying  reconciliations  to  corresponding  GAAP  financial  measures  included  in  the  tables  below,  may  provide  a  more 
complete understanding of factors and trends affecting our business.  These non-GAAP financial measures should not be relied 
upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Vistra Energy and must 
be considered in conjunction with GAAP measures.  In addition, non-GAAP financial measures are not standardized; therefore,
it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same 
or similar names.  We strongly encourage investors to review our consolidated financial statements and publicly filed reports in
their entirety and not rely on any single financial measure.

60

EBITDA and Adjusted EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of our 
operating performance.  We consider EBITDA as another way to measure financial performance on an ongoing basis.  Adjusted 
EBITDA is meant to reflect the operating performance of our segments for the period presented.  We define EBITDA as earnings
(loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense.  We define Adjusted 
EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of certain assets, (ii) the impacts of mark-
to-market changes on derivatives related to our portfolio, (iii) the impact of impairment charges, (iv) certain amounts associated 
with fresh-start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) 
impacts from the Tax Receivable Agreement and (vii) other material nonrecurring or unusual items.

aa

Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our 
ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe 
they provide useful information for our shareholders.

When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly 

comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).

Adjusted EBITDA — Successor Years Ended December 31, 2018 and 2017 and the period from October 3, 2016 through 
December 31, 2016

Net income (loss)

Income tax expense (benefit)
Interest expense and related charges
Depreciation and amortization (a)

EBITDA before Adjustments

Unrealized net loss resulting from hedging transactions
Generation plant retirement expenses
Fresh start/purchase accounting impacts
Impacts of Tax Receivable Agreement
Reorganization items and restructuring expenses
Non-cash compensation expenses
Transition and merger expenses
Severance
Other, net

Adjusted EBITDA, including Odessa earnout buybacks
Odessa earnout buybacks
Adjusted EBITDA

$

$

$

Successor

Year Ended December 31,

2018

2017

Favorable 
(Unfavorable) 
$ Change

(56) $
(45)
572
1,472
1,943
380
—
41
79
—
73
233
—
(7)
2,742
18
2,760

$

$

(254) $
504
193
781
1,224
146
206
59
(213)
3
19
27
—
(16)
1,455
—
1,455

$

$

198
(549)
379
691
719
234
(206)
(18)
292
(3)
54
206
—
9
1,287
18
1,305

Period from
October 3, 2016 
through 
December 31, 2016
(163)
$
(70)
60
247
74
165
—
35
22
18
—
—
44
10
368

$

____________
(a)  Includes nuclear fuel amortization in the ERCOT segment of $78 million, $82 million and $31 million for the Successor 
period for the years ended December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016,
respectively.

61

Successor

Year Ended December 31, 2018

Retail

712
—

7

318

1,037

ERCOT
$

(55) $
—

12

494

451

(206)

498

26

—

—

1
(13)

845

(6)

—

—

9
(2)

950

18

PJM

NY/NE

MISO

$

100
—

8

413

521

42

(1)

—

—

14
16

$

79
—

2

152

233

40

9

—

—

2
9

592

293

35
—

1

9

45

(9)

12

—

—

9
9

66

Asset
Closure
$

Eliminations
/ Corporate
and Other

(49) $
—

(878) $
(45)

Vistra 
Energy
Consolidated
(56)
(45)

—

—

542

86

572

1,472

(49)

(295)

1,943

—

1

—

—

2
(3)

15

—

79

73

196
(23)

(49) $

45

380

41

79

73

233
(7)

2,742

18

$

845

$

968

$

592

$

293

$

66

$

(49) $

45

$

2,760

Net income (loss)

$

Income tax benefit
Interest expense and related
charges
Depreciation and
amortization (a)
EBITDA before
Adjustments

Unrealized net (gain) loss
resulting from hedging
transactions
Fresh start/purchase
accounting impacts
Impacts of Tax Receivable
Agreement
Non-cash compensation
expenses
Transition and merger
expenses
Other, net

y

Adjusted EBITDA,
including Odessa earnout
buybacks
Odessa earnout buybacks
Adjusted EBITDA

____________
(a)  Includes nuclear fuel amortization of $78 million in ERCOT segment.

Successor

Year Ended December 31, 2017

Net income (loss)

Income tax expense
Interest expense and related charges
Depreciation and amortization (a)

EBITDA before Adjustments

Unrealized net (gain) loss resulting from hedging transactions
Generation plant retirement expenses
Fresh start accounting impacts
Impacts of Tax Receivable Agreement
Reorganization items and restructuring expenses
Non-cash compensation expenses
Transition and merger expenses
Other, net

Adjusted EBITDA

Retail

495
—
—
430
925
(171)
—
46
—
—
—
1
(22)
779

$

$

____________
(a)  Includes nuclear fuel amortization of $82 million in ERCOT segment.

62

$

Asset 
Closure

Eliminations
/ Corporate
and Other

ERCOT
$

(118) $
—
21
311
214
317
—
(1)
—
—
—
8
—
538

$

(63) $
—
—
1
(62)
—
206
14
—
—
—
—
—
158

$

Vistra
Energy
Consolidated
(254)
504
193
781
1,224
146
206
59
(213)
3
19
27
(16)
1,455

(568) $
504
172
39
147
—
—
—
(213)
3
19
18
6
(20) $

Adjusted EBITDA increased by $1,305 million to $2,760 million in the year ended December 31, 2018 compared to the year 

ended December 31, 2017, primarily due to the following:

PJM, MISO and NY/NE segments acquired in the Merger
Increase in ERCOT segment driven by operations acquired in the Merger and Odessa, higher realized prices
and the impact of the Comanche Peak outage in 2017 and related insurance proceeds in 2018
Increase in Retail segment driven by favorable volumes in ERCOT and Midwest/Northeast retail businesses
acquired in the Merger
Decrease in Asset Closure segment driven by retirement of facilities in first quarter of 2018, partially offset
by the change in estimates for certain AROs in 2018
Corporate and Other due in part to operations acquired in the Merger

Total

$

$

950

430

66

(207)
66
1,305

Period from October 3, 2016 through December 31, 2016

Successor

ERCOT
$

Asset
Closure
17
—
—
—
17
—
3
—
—
2
—
22

(268) $
—
(1)
84
(185)
272
(4)
—
7
33
9
132

$

$

$

Eliminations
/ Corporate
and Other
$

Vistra 
Energy
Consolidated
(163)
(70)
60
247
74
165
35
22
18
44
10
368

(26) $
(70)
61
10
(25)
—
—
22
4
—
—
1

$

Net income (loss)

Income tax benefit
Interest expense and related charges
Depreciation and amortization (a)

EBITDA before Adjustments

Unrealized net (gain) loss resulting from hedging transactions
Fresh start accounting impacts
Impacts of Tax Receivable Agreement
Reorganization items and restructuring expenses
Severance
Other, net

Adjusted EBITDA

Retail

114
—
—
153
267
(107)
36
—
7
9
1
213

$

$

____________
(a)  Includes nuclear fuel amortization of $31 million in ERCOT segment.

63

Retail Segment — Year Ended December 31, 2018 Compared to Year Ended December 31, 2018

—

Operating revenues:

Revenues in ERCOT
Revenues in Northeast/Midwest
Amortization expense
Other revenues

Total operating revenues

Fuel, purchased power costs and delivery fees:

Purchases from affiliates
Unrealized net gains on hedging activities with affiliates
Delivery fees
Other costs

Total fuel, purchased power costs and delivery fees

Net income

Adjusted EBITDA

Sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT
Sales volumes in Northeast/Midwest

Total retail electricity sales volumes

Weather (North Texas average) - percent of normal (a):
Cooling degree days
Heating degree days

Year Ended December 31,

2018

2017

Favorable
(Unfavorable) 
Change

$

$

$

$

$

4,426
1,123
(26)
74
5,597

(2,846)
218
(1,493)
(5)
(4,126)

712

845

$

$

$

$

$

4,002
—
(46)
102
4,058

(1,539)
154
(1,345)
(3)
(2,733)

495

779

$

$

$

$

$

424
1,123
20
(28)
1,539

(1,307)
64
(148)
(2)
(1,393)

217

66

42,992
20,739
63,731

39,032
—
39,032

3,960
20,739
24,699

103.0%
112.0%

99.1%
72.0%

____________
(a)  Weather data is obtained from Weatherbank, Inc.  For the year ended December 31, 2018, normal is defined as the average 
over the 10-year period from 2008 to 2017.  For the year ended December 31, 2017, normal is defined as the average over 
the 10-year period from 2007 to 2016.

Net income increased by $217 million to net income of $712 million and Adjusted EBITDA increased by $66 million to 
$845 million and in the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to the 
following:

Favorable volumes primarily due to weather in ERCOT
Margins in Midwest/Northeast acquired in the Merger
Unfavorable margins in ERCOT primarily due to higher power costs

Change in Adjusted EBITDA

Lower depreciation and amortization expenses driven by reduced amortization of the retail customer
relationship
Favorable impact of unrealized net gains on hedging activities
Higher other expenses

Change in Net income

$

$

$

53
34
(21)
66

132
34
(15)
217

64

ERCOT Segment — Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

—

Operating revenues:

Wholesale electricity sales
Sales to affiliates
Rolloff of unrealized net gains (losses) representing positions settled in
the current period
Unrealized net gains (losses) from changes in fair value
Unrealized net losses on hedging activities with affiliates
Other revenues

Operating revenues

Fuel, purchased power costs and delivery fees:

Fuel for generation facilities and purchased power costs
Unrealized losses from hedging activities
Ancillary and other costs

Fuel, purchased power costs and delivery fees

Net loss

Adjusted EBITDA

Production volumes (GWh):
Nuclear facilities
Lignite and coal facilities
Natural gas facilities
Solar facilities
Capacity factors:
Nuclear facilities
Lignite and coal facilities
CCGT facilities
Market pricing:
Average ERCOT North power price ($/MWh)

Year Ended December 31,

2018

2017

Favorable
(Unfavorable) 
Change

766
290

588
(722)
(44)
(38)
840

(486)
(3)
(51)
(540)

63

430

3,495
3,108
17,268
344

$

$

$

$

$

$

$

$

$

$

1,289
1,829

404
(689)
(198)
(1)
2,634

(1,367)
(15)
(139)
(1,521)

(55)

968

20,416
29,151
35,790
344

101.3%
76.9%
58.8%

523
1,539

(184)
33
(154)
37
1,794

(881)
(12)
(88)
(981)

(118)

538

$

$

$

$

$

16,921
26,043
18,522
—

84.0%
77.2%
52.3%

$

29.96

$

23.26

$

6.70

65

Net loss increased by $63 million to $55 million net loss and Adjusted EBITDA increased by $430 million to $968 million 

in the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to the following:

Favorable margins driven by higher realized power prices and increased production from legacy gas and coal
generation
Impact of operations acquired in the Merger
Impact related to Comanche Peak outage in 2017
Impact of full year of operations from Odessa acquired in 2017
Lower selling, general and administrative expenses
Insurance reimbursement for Comanche Peak
Other

Change in Adjusted EBITDA

Increased depreciation and amortization driven by facilities acquired in the Merger
Unfavorable impact of unrealized net losses on hedging activities
Partial buybacks of the Odessa earn-out provision in 2018
Other

Change in Net loss

$

$

$

180
73
74
86
34
21
(38)
430
(183)
(182)
(18)
(2)
63

66

PJM, NY/NE and MISO Segments — Year Ended December 31, 2018

—

Operating revenues:

Energy
Capacity
Unrealized net gains (losses) on hedging activities
Sales to affiliates
Unrealized net gains (losses) on hedging activities with affiliates
Other revenues

Operating revenues

Fuel, purchased power costs and delivery fees:

Fuel for generation facilities and purchased power costs
Fuel for generation facilities and purchased power costs from affiliates
Unrealized gains from hedging activities
Other costs

Fuel, purchased power costs and delivery fees

Net income

Adjusted EBITDA

Production volumes (GWh)

Capacity factors:
CCGT facilities
Coal facilities

Weather - percent of normal (a):

Cooling degree days
Heating degree days

Average Market On-Peak Power Prices ($/MWh) (b):

PJM West
AD Hub
New York - Zone C
Mass Hub

Average natural gas price - TetcoM3 ($/MMBtu) (c)

Average natural gas price - Algonquin Citygates ($/MMBtu) (c)

Year Ended December 31, 2018

PJM

NY/NE

MISO

775
369
(17)
628
(33)
3
1,725

(916)
(8)
8
(1)
(917)

100

592

$

$

$

$

$

582
239
(37)
44
(3)
(8)
817

(479)
—
—
(6)
(485)

79

293

$

$

$

$

$

370
53
(13)
302
16
(8)
720

(449)
30
6
(7)
(420)

35

66

40,533

14,605

21,324

67.8%
63.2%

121.0%
101.0%

41.79
40.47

3.69

48.2%
—%

118.0%
102.0%

—%
63.3%

134.0%
95.0%

$
$

$

37.03
50.11

4.84

$

$

$

$

$

$
$

$

____________
(a) Reflects cooling degree days or heating degree days for the region based on Weather Services International (WSI) data.  For

the year ended December 31, 2018, represents April 9, 2018 through December 31, 2018 only.

(b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.  

For the year ended December 31, 2018, represents April 9, 2018 through December 31, 2018 only.

(c) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.  For the year 

ended December 31, 2018, represents April 9, 2018 through December 31, 2018 only.

67

Net income totaled $100 million, $79 million and $35 million and Adjusted EBITDA totaled $592 million, $293 million and 

$66 million in the year ended December 31, 2018, for PJM, NY/NE and MISO segments respectively.

Generation revenue net of fuel
Capacity revenue
Operating costs
Selling, general and administrative expenses
Equity income from unconsolidated investment and other
Other

Adjusted EBITDA

Depreciation and amortization
Unrealized net gains (losses) on hedging activities
Purchase accounting impacts
Transition and merger expenses
Other

Net income

PJM

NY/NE

MISO

481
369
(243)
(52)
7
30
592
(413)
(42)
1
(14)
(24)
100

$

$

$

116
260
(74)
(37)
11
17
293
(152)
(40)
(9)
(2)
(11)
79

$

$

$

229
61
(202)
(52)
—
30
66
(9)
9
(12)
(9)
(10)
35

$

$

$

Asset Closure Segment — Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 

—

Year Ended December 31,

2018

2017

Favorable
(Unfavorable) 
Change

Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Impairment of long-lived assets
Operating income (loss)

Other income
Other deductions

Income (loss) before income taxes

Income tax expense

Net income (loss)

Depreciation and amortization

EBITDA

Generation plant retirement expenses
Fresh start accounting impacts
Transition and merger expenses
Other

Adjusted EBITDA

Production volumes (GWh)

$

$

$

$

50
(40)
(43)
—
(17)
—
(50)
2
(1)
(49)
—
(49) $
—
(49)
—
1
2
(3)
(49) $

$

964
(607)
(380)
(1)
(19)
(25)
(68)
6
(1)
(63)
—
(63) $
1
(62)
206
14
—
—
158

$

(914)
567
337
1
2
25
18
(4)
—
14
—
14
(1)
13
(206)
(13)
2
(3)
(207)

1,159

25,392

(24,233)

Results for the Asset Closure segment reflect the retirement of the Stuart and Killen plants in May 2018 (acquired in the 
Merger), retirement of the Northeastern waste coal plant in October 2018 and the retirement of the Monticello, Sandow and Big
Brown plants in January and February 2018 (see Note 4 to the Financial Statements) and corresponding 95% decrease in volume
in the year ended December 31, 2018.  Operating costs for the year ended December 31, 2018 included ongoing costs associated 
with closing these plants as well as a favorable adjustment to the estimated asset retirement obligation of $56 million.

68

Predecessor Consolidated Financial Results — Period from January 1, 2016 through October 2, 2016

—

Operating revenues
Fuel, purchased power costs and delivery fees
Net gain from commodity hedging and trading activities
Operating costs
Depreciation and amortization
Selling, general and administrative expenses

Operating income (loss)

Other income
Other deductions
Interest expense and related charges
Reorganization items

Income (loss) before income taxes

Income tax benefit

Net income (loss)

Predecessor

Period from
January 1, 2016
through
October 2, 2016
3,973
$
(2,082)
282
(664)
(459)
(482)
568
19
(75)
(1,049)
22,121
21,584
1,267
22,851

$

69

Predecessor Operating Statistics — Period from January 1, 2016 through October 2, 2016

—

Operating revenues:
Retail electricity revenues
Wholesale electricity revenues and other operating revenues (a)(b)

Total operating revenues

Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs (a)
Other costs
Delivery fees
Total

Sales volumes (GWh):
Retail electricity sales volumes
Wholesale electricity sales volumes (b)

Production volumes (GWh):
Nuclear facilities
Lignite and coal facilities (c)
Natural gas facilities

Capacity factors:
Nuclear facilities
Lignite and coal facilities (c)
CCGT facilities

Market pricing:
Average ERCOT North power price ($/MWh)

Weather (North Texas average) - percent of normal (d):
Cooling degree days
Heating degree days

Predecessor

Period from
January 1, 2016
through 
October 2, 2016

$

$

$

$

3,154
819
3,973

950
108
1,024
2,082

30,973
25,563

15,005
31,865
8,539

99.2%
60.5%
65.2%

$

20.78

102.8%
81.9%

____________
(a)  Upon settlement, physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity
sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power 
costs are reported at approximated market prices, as required by accounting rules, rather than contract price.  The offsetting 
differences between contract and market prices are reported in net gain from commodity hedging and trading activities.

(b)  Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
(c)  Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal-fueled units totaling

14,420 GWh for the period from January 1, 2016 through October 2, 2016.

(d)  Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from 
reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of 
Commerce).  Normal is defined as the average over the 10-year period from 2000 to 2010.

70

Predecessor Financial Results — Period from January 1, 2016 through October 2, 2016

—

For the period from January 1, 2016 through October 2, 2016, income before income taxes totaled $21.584 billion and 
included a $24.252 billion gain on reorganization adjustments and a $2.013 billion loss for the net impacts from the adoption of 
fresh start reporting (see Notes 5 and 7 to the Financial Statements).  Results also reflected the effect of declining average electricity 
prices on operating revenues, $977 million in adequate protection interest expense paid/accrued on pre-petition debt and $116 
million in reorganization items associated with the Chapter 11 Cases.

Operating revenues totaled $3.973 billion for the period from January 1, 2016 through October 2, 2016.  Retail electricity 
revenues totaled $3.154 billion and were negatively impacted by declining average prices and reduced volumes reflecting milder 
than normal weather in 2016.  Wholesale revenues totaled $649 million and were positively impacted by increases in generation
volumes (approximately 8,048 GWh) driven by the Lamar and Forney generation assets acquired in April 2016 (see Note 3 to the 
Financial Statements), partially offset by lower average wholesale electricity prices.

Following is an analysis of amounts reported as net losses from commodity hedging and trading activities.  Results are

primarily related to natural gas and power hedging activity.

Realized net gains
Unrealized net gains (losses)

Total

Predecessor

Period from
January 1, 2016 
through 
October 2, 2016
320
$
(38)
282

$

The negative impacts of declining average prices on wholesale operating revenues were partially offset by realized net gains
reflecting settled gains on derivatives due to declining market prices.  These gains were primarily related to natural gas positions.

For the period from January 1, 2016 through October 2, 2016, net unrealized losses were primarily impacted by reversals 

of previously recorded unrealized net gains on settled positions.

Fuel, purchased power costs and delivery fees totaled $2.082 billion for the period from January 1, 2016 through October 
2, 2016 reflecting the impact of declining electricity prices on purchased power costs during 2016, partially offset by incremental
natural gas fuel costs associated with the Lamar and Forney Acquisition.

Operating costs totaled $664 million for the period from January 1, 2016 through October 2, 2016 and primarily reflect 
maintenance expense for generation assets, including the scope and timing of maintenance costs at lignite/coal-fueled generation
facilities.  Operating costs were also impacted by incremental operation and maintenance costs associated with the Lamar and 
Forney Acquisition.

Depreciation and amortization expenses totaled $459 million for the period from January 1, 2016 through October 2, 2016 
and primarily reflected depreciation on power generation and mining property, plant and equipment and amortization of identifiable 
intangible assets.  Depreciation and amortization expenses were also impacted by incremental depreciation expense associated 
with the Lamar and Forney Acquisition.

a

SG&A expenses totaled $482 million for the period from January 1, 2016 through October 2, 2016 and reflected administrative

and general salaries, employee benefits, marketing costs related to retail electricity activity and other administrative costs.

Results also include $32 million of severance expense, primarily reported in fuel, purchased power costs and delivery fees
and operating costs, associated with certain actions taken to reduce costs related to mining and lignite/coal generation operations.

For the period from January 1, 2016 through October 2, 2016, interest expense and related charges totaled $1.049 billion
and included adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors totaling 
$977 million and interest expense on debtor-in-possession financing totaling $76 million.

71

Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the periods presented.  The net 
change in these assets and liabilities, excluding "other activity" as described below, reflects $380 million, $145 million, $166
million and $38 million in unrealized net losses for the Successor period for the year ended December 31, 2018 and 2017 and the
period from October 3, 2016 through December 31, 2016, and the Predecessor period from January 1, 2016 through October 2, 
2016, respectively, all arising from mark-to-market accounting for positions in the commodity contract portfolio.

Commodity contract net asset (liability) at beginning of period
Settlements/termination of positions (a)
Changes in fair value of positions in the portfolio (b)
Acquired commodity contracts in Merger (c)
Other activity (d)
Commodity contract net asset (liability) at end of period

$

$

(96) $
457
(837)
(454)
80
(850) $

Successor

Year Ended
December
31, 2018

Year Ended
December
31, 2017

Period from
October 3, 2016
through
December 31, 2016
181
$
(95)
(71)
—
49
64

64
(207)
62
—
(15)
(96) $

Predecessor
Period from
January 1, 2016 
through
October 2, 2016
271
$
(232)
194
—
(35)
198

$

(a)  Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains
and losses recognized in the settlement period).  The years ended December 31, 2018 and 2017 include reversals of $17
million and $63 million, respectively of previously recorded unrealized gains related to Vistra Energy beginning balances.
The year ended December 31, 2018 also includes reversal of $320 million of previously recorded unrealized losses related 
to commodity contracts acquired in the Merger.  Excludes changes in fair value in the month the position settled as well as
amounts related to positions entered into, and settled, in the same month.

(b)  Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value.  Excludes changes in fair 
value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

ff

(c)  Includes fair value of commodity contracts acquired at the Merger Date (see Note 2 to the Financial Statements).
(d)  Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses.  
Amounts are generally related to premiums related to options purchased or sold as well as  certain margin deposits classified 
as settlement for certain transactions executed on the CME.

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values 

at December 31, 2018, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

Source of fair value
Prices actively quoted
Prices provided by other external sources
Prices based on models

Total

Successor

Maturity dates of unrealized commodity contract net liability at December 31, 2018

Less than
1 year

1-3 years

4-5 years

Excess of
5 years

Total

$

$

(106)
(507)
(59)
(672)

$

$

5
(107)
(64)
(166)

$

$

— $
—
(12)
(12)

$

— $
—
—
— $

(101)
(614)
(135)
(850)

72

FINANCIAL CONDITION

Operating Cash Flows

Successor — Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 — Cash provided by operating 
activities totaled $1.471 billion and $1.386 billion in the years ended December 31, 2018 and 2017, respectively.  The favorable
change of $85 million was primarily driven by increased cash from operations reflecting operations acquired in the Merger largely
offset by increased interest paid of $406 million due to the assumption of long-term debt obligations in the Merger, an increase
in cash used for margin deposits of $367 million related to derivative contracts and $238 million in proceeds received in 2017 
from the Alcoa contract settlement.

7

6
Period from October 3, 2016 through December 31, 2016 — Cash provided by operating activities totaled $81 million and 
was primarily driven by cash earnings from our business of approximately $251 million after taking into consideration depreciation
and amortization and unrealized mark-to-market losses on derivatives, offset by a net use of cash of approximately $170 million
in working capital primarily driven by cash utilized in margin postings related to derivative contracts.

Depreciation  and  Amortization  —  Depreciation  and  amortization  expense  reported  as  a  reconciling  adjustment  in  the
statements of consolidated cash flows exceeds the amount reported in the statements of consolidated income (loss) by $139 million,
$136 million and $69 million for the year ended December 31, 2018 and 2017 and the period from October 3, 2016 through
December 31, 2016, respectively.  The difference represented amortization of nuclear fuel, which is reported as fuel costs in thet
statements of consolidated income (loss) consistent with industry practice, and amortization of intangible net assets and liabilities
that are reported in various other statements of consolidated income (loss) line items including operating revenues and fuel and 
purchased power costs and delivery fees.

Predecessor — Period from January 1, 2016 through October 2, 2016 — Cash used in operating activities totaled $238

6

million and was primarily driven by cash used for margin deposit postings and other working capital utilization.

Financing Cash Flows

Successor — Year Ended December 31, 2018 — Cash used in financing activities totaled $2.723 billion and reflected:

•  cash tender offers to purchase $1.542 billion of senior notes assumed in the Merger;
• 

the amendment to the Vistra Operations Credit Facilities, including the repayment of $500 million in borrowings under 
the Term C Facility;
the redemption of $850 million principal amount of outstanding 6.75% Senior Notes in May 2018;
the repurchases of $119 million principal amount of outstanding Vistra Energy senior notes in November and December 
2018;

• 
• 

•  premium amounts paid in connection with the debt tender offer and other debt financing fees totaling $236 million, and
•  $763 million of cash paid for share repurchases during 2018,

partially offset by:

the issuance of $1.0 billion principal amount of Vistra Operations 5.500% senior notes due 2026, and

• 
•  proceeds of $339 million from the accounts receivable securitization program.

Year Ended December 31, 2017 — Cash used in financing activities totaled $201 million and reflected the repayment of 
debt, including the repayment of $150 million in principal under the Term Loan C Facility (see Note 14 to the Financial Statements).

7

Period from October 3, 2016 through December 31, 2016 — Cash provided by financing activities totaled $6 million and 

6

related to the net impacts of the Incremental Term Loan B borrowings and the Special Dividend paid to shareholders.

Predecessor — Period from January 1, 2016 through October 2, 2016 — Cash provided by financing activities totaled 
$1.059 billion and primarily reflected $2.040 billion in net borrowings under the DIP Roll Facilities and the DIP Facility, including 
$870 million in net borrowings to fund the Lamar and Forney Acquisition (see Note 3 to the Financial Statements), and $69 million 
from  the  issuance  of  preferred  stock,  partially  offset  by  $915  million  in  payments  to  extinguish  claims  under  the  Plan  of 
Reorganization and $112 million in fees related to the issuance of the DIP Roll Facilities.

6

73

Investing Cash Flows

Successor — Year Ended December 31, 2018 — Cash used in investing activities totaled $101 million and reflected  capital 
expenditures  (including  LTSA  prepayments  and  nuclear  fuel  purchases)  totaling  $496  million  and  development  and  growth
expenditures totaling $34 million, partially offset by $445 million of cash acquired in the Merger.

Capital expenditures, including nuclear fuel, in the year ended December 31, 2018 totaled $496 million and consisted of:

• 
• 
• 
• 

$208 million primarily for our generation and mining operations;
$118 million for nuclear fuel purchases;
$70 million for information technology, other corporate investments and Comanche Peak repairs, and
$100 million for LTSA prepayments.

Year  Ended  December 31,  2017  —  Cash  used  in  investing  activities  totaled  $727  million  and  was  primarily  driven  by
payments of $355 million related to the Odessa Acquisition, Upton 2 solar development expenditures totaling $190 million and 
capital expenditures (including nuclear fuel purchases) totaling $176 million.  The Odessa Acquisition and the Upton 2 solar 
development were funded using cash on hand.

7

Capital expenditures, including nuclear fuel, in the year ended December 31, 2017 totaled $176 million and consisted of:

• 
• 
• 

$88 million primarily for our generation and mining operations;
$62 million for nuclear fuel purchases, and
$26 million for information technology and other corporate investments.

Period from October 3, 2016 through December 31, 2016 — Cash used in investing activities totaled $93 million and was

6

primarily driven by capital expenditures (including nuclear fuel purchases) totaling $89 million.

Capital expenditures, including nuclear fuel, in the period from October 3, 2016 through December 31, 2016 totaled $89 

million and consisted of:

• 
• 
• 

$40 million primarily for our generation and mining operations;
$41 million for nuclear fuel purchases, and
$8 million for information technology and other corporate investments.

Predecessor — Period from January 1, 2016 through October 2, 2016 — Cash used in investing activities totaled $1.420
billion and was primarily driven by payments of $1.343 billion related to the Lamar and Forney Acquisition net of cash acquired
(see Note 3 to the Financial Statements) and capital expenditures (including nuclear fuel purchases) totaling $263 million.

6

Capital expenditures, including nuclear fuel, in the period from January 1, 2016 through October 2, 2016 totaled $263 million

and consisted of:

• 
• 
• 

$211 million primarily for our generation and mining operations;
$33 million for nuclear fuel purchases, and
$19 million for information technology and other corporate investments.

Debt Activity

See Note 14 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.

74

Available Liquidity

The following table summarizes changes in available liquidity for the year ended December 31, 2018:

Cash and cash equivalents (a)
Vistra Operations Credit Facilities — Revolving Credit Facility
Vistra Operations Credit Facilities — Term Loan C Facility (b)

Total available liquidity

December 31, 2018
636
$
1,135
—
1,771

$

December 31, 2017
1,487
$
834
7
2,328

$

$

$

Change

(851)
301
(7)
(557)

___________
(a)  Cash and cash equivalents excludes $500 million of restricted cash held for letter of credit support at December 31, 2017

(see Note 23 to the Financial Statements).

(b)  The Term Loan C Facility was used for issuing letters of credit for general corporate purposes.  Borrowings totaling $500 
million were held in collateral accounts at December 31, 2017, and were reported as restricted cash in our consolidated 
balance sheets.  In June 2018, the Vistra Operations Credit Facilities were amended, and the Term Loan C Facility was repaid 
using $500 million of cash from the collateral accounts used to backstop letters of credit.

The decrease in available liquidity of $557 million in the year ended December 31, 2018 was primarily driven by cash tender 
offers to purchase $1.542 billion of senior notes assumed in the Merger, the redemption of $850 million principal amount of 
outstanding 6.75% senior notes, the amendment to the Vistra Operations Credit Facilities, the repurchases of $119 million principal
amount of outstanding Vistra Energy senior notes and $763 million in cash paid for share repurchases, partially offset by the 
issuance of $1.0 billion principal amount of Vistra Operations 5.500% senior notes, $445 million of cash acquired in the Merger,rr
increased  available  capacity  under  the  Revolving  Credit  Facility  and  proceeds  of  $339  million  from  the  accounts  receivable
securitization program.

Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated 
cash requirements, including those related to our capital allocation initiatives, through at least the next 12 months.  Our operational 
cash flows tend to be seasonal and weighted toward the second half of the year.

Capital Expenditures

Estimated capital expenditures and nuclear fuel purchases for 2019 are expected to total approximately $629 million and 

include:

• 
• 
• 
• 

$432 million for investments in generation and mining facilities;
$74 million for nuclear fuel purchases;
$80 million for information technology and other corporate investments, and
$43 million for growth and development.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of 
the underlying commodity moves such that the hedging or trading instrument we hold has declined in value.  We use cash, letters
of credit and other forms of credit support to satisfy such collateral posting obligations.  See Note 14 to the Financial Statements
for discussion of the Vistra Operations Credit Facilities.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into 
account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted 
to take into account changes in the value of the underlying commodity).  The amount of initial margin required is generally defined 
by exchange rules.  Clearing agents, however, typically have the right to request additional initial margin based on various factors, 
including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms 
as negotiated with the clearing agent.  Cash collateral received from counterparties is either used for working capital and other 
business purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and 
restricted  from  being  used  for  working  capital  and  other  corporate  purposes.   With  respect  to  over-the-counter  transactions, 
counterparties generally have the right to substitute letters of credit for such cash collateral.  In such event, the cash collateral 
previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.

r

ff

75

At December 31, 2018, we received or posted cash and letters of credit for commodity hedging and trading activities as 

follows:

• 
• 
• 

• 

$361 million in cash has been posted with counterparties as compared to $30 million posted at December 31, 2017;
$4 million in cash has been received from counterparties as compared to $4 million received at December 31, 2017;
$1.185  billion  in  letters  of  credit  have  been  posted  with  counterparties  as  compared  to  $390  million  posted  at 
December 31, 2017, and
$12 million in letters of credit have been received from counterparties as compared to $3 million received at December 31, 
2017.

Income Tax Payments

In the next 12 months, we do not expect to make federal income tax payments due to Vistra Energy's forecasted loss position.  
In February 2019, we received a refund of $21 million related to Vistra Energy's 2017 federal tax return.  We expect to make state 
income tax payments of approximately $30 million in the next 12 months.  For the year ended December 31, 2018, federal income 
tax payments totaled $45 million, state income tax payments totaled $22 million and TRA payments totaled $16 million.

Capitalization

Our  capitalization  ratios  consisted  of  58%  and  41%  long-term  debt  (less  amounts  due  currently)  and  42%  and  59% 
shareholders' equity at December 31, 2018 and 2017, respectively.  Total long-term debt (including amounts due currently) to 
capitalization was 58% and 41% at December 31, 2018 and 2017, respectively.

Financial Covenants

The Credit Facilities Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely during
a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of 
credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first lien net leverage 
ratio not exceed 4.25 to 1.00.  As of December 31, 2018, we were in compliance with this financial covenant.

See Note 14 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Collateral Support Obligations

The RCT has rules in place to assure that parties can meet their mining reclamation obligations.  In September 2016, the 
RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations.  The collateral bond is 
effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that 
contractually enables the RCT to be paid (up to $975 million) before the other first lien lenders in the event of a liquidation of our 
assets.  Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been 
obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the
RCT, and includes cost contingency amounts.

n

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer 
deposits, if necessary.  Under these rules, at December 31, 2018, Vistra Energy has posted letters of credit in the amount of $55
million with the PUCT, which is subject to adjustments.

The RTOs/ISOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets 
operated by those RTOs/ISOs.  Under these rules, Vistra Energy has posted collateral support totaling $181 million in the form 
of letters of credit, $10 million in the form of a surety bond and $1 million in cash at December 31, 2018 (which is subject to daily
adjustments based on settlement activity with the RTOs/ISOs).

Material Cross Default/Acceleration Provisions

Certain of our contractual arrangements contain provisions that could result in an event of default if there was a failure under 
financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due.  Such 
provisions are referred to as "cross default" or "cross acceleration" provisions.

76

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate
amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities.  Such a default would 
allow the lenders to accelerate the maturity of outstanding balances (approximately $5.8 billion at December 31, 2018) under such 
facilities.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are 
secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross default 
provision.  An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness in excess of $300 million
that results in the acceleration of such debt, would give each counterparty under these hedging agreements the right to terminate 
its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations
under such agreement to be settled.

Under Vistra Operations' senior notes indenture, a default under any document evidencing indebtedness for borrowed money 
by Vistra Operations or any subsidiary guarantor for failure to pay principal when due at final maturity or that results in the
acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a cross default under the senior 
notes.

Each of Vistra Energy's indentures for each series of senior notes (except with respect to the Consent Senior Notes) and the 
TEUs, respectively, contain a cross default provision.  A default by Vistra Energy, as issuer of each series of senior notes and the
TEUs, respectively, in respect of certain specified indebtedness in an aggregate amount in excess of $100 million may result in a n
cross default under the respective indentures of the senior notes and TEUs.  Such a default would allow the trustee or noteholders
holding at least 25% in principal amount of the respective series of senior notes or TEUs that are outstanding (each such series
treated as a separate class) to accelerate the maturity of such portion of the principal amount of all securities of such series of 
senior notes or TEUs, respectively.

Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions 
whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of 
borrowings in excess of thresholds, which may vary by contract.

The Receivables Program contains a cross default provision. The cross default provision applies, among other instances, if 
Vistra Operations, the performance guarantor, fails to make a payment of principal or interest on any indebtedness that is outstanding 
in a principal amount of at least $300 million, or, in the case of TXU Energy, the originator and servicer, in a principal amount of 
at least $50 million, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the
debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity.  If this cross default 
provision  is  triggered,  a  termination  event  under  the  Receivables  Facility  would  occur  and  the  Receivables  Facility  may  be 
terminated.

uu

a

Under the Vistra Operations' alternative letter of credit program, a default under any document evidencing indebtedness for 
borrowed money by Vistra Operations or any subsidiary guarantor for failure to pay principal when due at final maturity or that
results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of
the facility.

77

Contractual Obligations and Commitments

The following table summarizes the amounts and related maturities of our contractual cash obligations at December 31, 
2018.  See Notes 14 and 15 to the Financial Statements for additional disclosures regarding debts and noncancellable purchase
obligations.

Contractual Cash Obligations:
Debt – principal, including capital leases (a)

Debt – interest
Operating leases
Long-term service and maintenance contracts

Obligations under commodity purchase and services

agreements (b)

Total contractual cash obligations

$

$

Less Than
One Year

One to
Three
Years

Three to
Five
Years

More
Than Five
Years

$

191
611
35
175

$

334
1,207
54
316

$

5,932
990
39
316

$

4,453
474
168
2,619

Total
10,910
3,282
296
3,426

1,589
2,601

$

912
2,823

$

460
7,737

$

709
8,423

$

3,670
21,584

___________
(a)  Includes $5.813 billion of borrowings under the Vistra Operations Credit Facility, $3.626 billion principal amount of Vistra 
Energy senior notes, $1.0 billion principal amount of Vistra Operations senior notes and $471 million principal amount of 
long-term  debt,  including  forward  capacity  agreements,  equipment  financing  agreements  and  mandatorily  redeemable 
preferred stock.  Excludes unamortized premiums, discounts and debt costs.

(b)  Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear 
related outsourcing and other purchase commitments.  Amounts presented for variable priced contracts reflect the year-end 
2018 price for all periods except where contractual price adjustment or index-based prices are specified.

The following are not included in the table above:

• 
• 
• 
• 

• 
• 

the TRA obligation (see Note 10 to the Financial Statements);
asset retirement obligations (see Note 23 to the Financial Statements);
arrangements between affiliated entities and intercompany debt (see Note 21 to the Financial Statements);
individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one 
counterparty that are more than $1 million on an aggregated basis have been included);
contracts that are cancellable without payment of a substantial cancellation penalty, and
employment contracts with management.

Guarantees

See Note 15 to the Financial Statements for discussion of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements.

COMMITMENTS AND CONTINGENCIES

See Note 15 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

78

Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that in the normal course of business we may experience a loss in value due to changes in market 
conditions that affect economic factors such as commodity prices, interest rates and counterparty credit.  Our exposure to market 
risk is affected by several factors, including the size, duration and composition of our energy and financial portfolio, as well as
the volatility and liquidity of markets.  Instruments used to manage this exposure include interest rate swaps to hedge debt costs,
as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices.

Risk Oversight

We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive
energy business within limitations established by senior management and in accordance with overall risk management policies. 
Interest rate risk is managed centrally by our treasury function.  Market risks are monitored by risk management groups that operate 
independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies.  These techniques
measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market 
conditions and include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test 
scenarios.  Key risk control activities include, but are not limited to, transaction review and approval (including credit review),
operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation 
and reporting, and portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

rr

Vistra Energy has a risk management organization that enforces applicable risk limits, including the respective policies and 

procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses.

Commodity Price Risk

Our business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-
related products it markets or purchases.  We actively manage the portfolio of generation assets, fuel supply and retail sales load 
to mitigate the near-term impacts of these risks on results of operations.  Similar to other participants in the market, we cannot 
fully manage the long-term value impact of structural declines or increases in natural gas and power prices.

In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-
term  contracts  for  physical  delivery,  exchange-traded  and  over-the-counter  financial  contracts  and  bilateral  contracts  with
customers.   Activities  include  hedging,  the  structuring  of  long-term  contractual  arrangements  and  proprietary  trading.    We
continuously monitor the valuation of identified risks and adjust positions based on current market conditions.  We strive to use
consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio under 
a variety of market conditions.  The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence 
level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected 
market prices and volatilities.

Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate
changes in a portfolio's value based on assumed market conditions for liquid markets.  The use of this method requires a number
of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for 
management action, such as to liquidate positions), and (iii) historical estimates of volatility and correlation data.  The table below 
details a VaR measure related to various portfolios of contracts.

VaR for Underlying Generation Assets and Energy-Related Contracts — This measurement estimates the potential loss in
value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence level 
and an assumed holding period of 60 days for a forward period through December 2019.

Month-end average VaR
Month-end high VaR
Month-end low VaR

79

Year Ended December 31,

2018

2017

$
$
$

182
267
65

$
$
$

92
140
62

The increase in the month-end high VaR risk measure in 2018 reflects operations acquired in the Merger.

Interest Rate Risk

The following table provides information concerning our financial instruments at December 31, 2018 and 2017 that are 
sensitive to changes in interest rates.  Debt amounts consist of the Vistra Operations Credit Facilities.  See Note 14 to the Financial 
Statements for further discussion of these financial instruments.

Expected Maturity Date

(millions of dollars, except percentages)

2019

2020

2021

2022

2023

There-
after

2018
Total
Carrying
Amount

2018
Total
Fair
Value

2017
Total
Carrying
Amount

2017
Total
Fair
Value

Long-term debt,
including current
maturities (a):
Variable rate
debt amount
Average interest
rate (b)

Debt swapped to
fixed (c):

Notional
amount
Average pay
rate
Average receive
rate

$ 59

$

59

$

59

$

59

$ 3,640

$ 1,937

$ 5,813

$ 5,599

$4,311

$ 4,334

4.55% 4.55% 4.55% 4.55%

4.59%

4.47%

4.55%

3.98%

$ 159

$ 358

$ — $ — $ 3,000

$ 4,200

$ 7,717

$3,000

4.16% 4.10% 4.07% 4.07%

4.34%

5.01%

4.38%

4.56% 4.57% 4.57% 4.57%

4.53%

4.45%

4.53%

4.59%

4.11%

___________
(a)  Unamortized premiums, discounts and debt issuance costs are excluded from the table.
(b)  The weighted average interest rate presented is based on the rates in effect at December 31, 2018.
(c)  Interest rate swaps have maturity dates through July 2026.

At December 31, 2018, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-
point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $14 million, taking into account 
the interest rate swaps discussed in Note 14 to Financial Statements.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties.  We minimize credit risk by evaluating
potential  counterparties,  monitoring  ongoing  counterparty  risk  and  assessing  overall  portfolio  risk.    This  includes  review  of 
counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit 
criteria.  We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide
for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental 
guarantees and surety bonds.  See Note 18 to the Financial Statements for further discussion of this exposure.

Bankruptcies — We are party to (i) certain gas transportation agreements with Pacific Gas and Electric Corporation (PG&E) 
and (ii) in connection with the Moss Landing battery storage project, we entered into a long-term renewable power purchase 
agreement with PG&E, which was approved by the California Public Utilities Commission in November 2018.  PG&E filed for 
Chapter 11 bankruptcy protection in January 2019.

As of December 31, 2018, we had no outstanding accounts receivable from PG&E and accordingly, we have not recorded 
a  reserve  related  to  the  pre-petition  receivables.   While  our  assumptions  and  conclusions  may  change,  we  could  have  future
impairment losses, or specifically with respect to the gas transportation agreements, be required to seek alternative, higher-cost 
fuel transportation methods, if any of the terms of the contracts are not honored by PG&E or the contracts are rejected through
the bankruptcy process.

80

Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade
accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $975 
million at December 31, 2018.

At  December 31,  2018,  Retail  segment  credit  exposure  totaled  $683  million,  including  $676  million  of  trade  accounts 
receivable and $7 million related to derivative assets.  Cash deposits and letters of credit held as collateral for these receivables
totaled $38 million, resulting in a net exposure of $645 million.  We believe the risk of material loss (after consideration of bad 
debt  allowances)  from  nonperformance  by  these  customers  is  unlikely  based  upon  historical  experience.    Allowances  for 
uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical
experience, market or operational conditions and changes in the financial condition of large business customers.

f

At December 31, 2018, aggregate ERCOT, PJM, NY/NE and MISO segments credit exposure totaled $292 million including 
$147 million related to derivative assets and $145 million of trade accounts receivable, after taking into account master netting 
agreement provisions but excluding collateral impacts.

Including collateral posted to us by counterparties, our net ERCOT, PJM, NY/NE and MISO segments exposure was $281
million, substantially all of which is with investment grade customers as seen in the following table that presents the distribution 
of credit exposure at December 31, 2018.  Credit collateral includes cash and letters of credit, but excludes other credit enhancements
such as guarantees or liens on assets.

a

Investment grade
Below investment grade or no rating

Totals

Before Credit
Collateral

Credit
Collateral

Net
Exposure

$

$

247
45
292

$

$

— $
11
11

$

247
34
281

Significant (10% or greater) concentration of credit exposure exists with four counterparties, which represented an aggregate 
$195 million, or 70%, of the total net exposure.  We view exposure to these counterparties to be within an acceptable level of risk 
tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, the counterparties' market role and 
deemed creditworthiness and the importance of our business relationship with the counterparties.  An event of default by one or
more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts
such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us.

Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in
the  financial  statements  and  are  excluded  from  the  detail  above.    Such  contractual  commitments  may  contain  pricing  that  is
favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.

At December 31, 2018, interest rate swap exposure in the Corporate and Other non-segment totaled $51 million.  There are 

no collateral offsets.  The counterparty credit rating is investment grade.

81

FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements."  All statements, other than statements
of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address 
activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to
our  financial  or  operational  projections,  capital  allocation,  capital  expenditures,  liquidity,  dividend  policy,  business  strategy,
competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and 
industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases
such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "may," "projection," "target," 
"goal," "objective" and "outlook"), are forward-looking statements.  Although we believe that in making any such forward-looking 
statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and 
risks and is qualified in its entirety by reference to the discussion under Item 1A. Risk Factors and Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations in this report and the following important factors, among others,
that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements:

• 
• 
• 

the actions and decisions of judicial and regulatory authorities;
prohibitions and other restrictions on our operations due to the terms of our agreements;
prevailing federal, state and local governmental policies and regulatory actions, including those of the legislatures and 
other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the TRE, the public
utility commissions of states and locales in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the 
RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the MSHA and the CFTC,
with respect to, among other things:

allowed prices;
industry, market and rate structure;
purchased power and recovery of investments;
operations of nuclear generation facilities;
operations of fossil-fueled generation facilities;
operations of mines;
acquisition and disposal of assets and facilities;
development, construction and operation of facilities;
decommissioning costs;
present or prospective wholesale and retail competition;
changes  in  federal,  state  and  local  tax  laws,  rates  and  policies,  including  additional  regulation,  interpretations, 
amendments, or technical corrections to the TCJA;
changes in and compliance with environmental and safety laws and policies, including National Ambient Air Quality 
Standards,  the  Cross-State Air  Pollution  Rule,  the  Mercury  and Air  Toxics  Standard,  regional  haze  program
implementation and GHG and other climate change initiatives, and
clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;

• 

expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy 
of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations,
including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, 
and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an 
impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a
negative financial effect;
legal and administrative proceedings and settlements;
general industry trends;
economic conditions, including the impact of an economic downturn;

• 
• 
• 
•  weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of 

sabotage, wars or terrorist or cybersecurity threats or activities;
our ability to collect trade receivables from counterparties;
our ability to attract and retain profitable customers;
our ability to profitably serve our customers;
restrictions on competitive retail pricing;
changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation and 
storage thereof;
changes in the ability of vendors to provide or deliver commodities as needed;

• 
• 
• 
• 
• 
• 
• 

• 

82

 
 
 
 
 
 
 
 
 
 
 
 
 
• 

• 

• 
• 

• 

• 

• 
• 
• 
• 
• 

• 

• 
• 

• 

• 
• 
• 
• 
• 
• 
• 

• 

• 

• 
• 

• 

• 

• 

beliefs  and  assumptions  about  the  benefits  of  state-  or  federal-based  subsidies  to  our  market  competition,  and  the
corresponding impacts on us, including if such subsidies are disproportionately available to our competitors;
the effects of, or changes to, market design and the power and capacity procurement processes in the markets in which 
we operate;
changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets;
our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat 
rates and interest rates;
population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT, 
MISO and PJM;
our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives
in ISO-NE;
efforts to identify opportunities to reduce congestion and improve busbar power prices;
access to adequate transmission facilities to meet changing demands;
changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
changes in operating expenses, liquidity needs and capital expenditures;
commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international 
credit markets;
access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing 
efforts, including availability of funds in capital markets;
our ability to maintain prudent financial leverage;
our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt 
obligations;
our ability to implement our growth strategy, including the completion and integration of mergers, acquisitions and/or 
joint venture activity and identification and completion of sales and divestitures activity;
competition for new energy development and other business opportunities;
inability of various counterparties to meet their obligations with respect to our financial instruments;
counterparties' collateral demands and other factors affecting our liquidity position and financial condition;
changes in technology (including large scale electricity storage) used by and services offered by us;
changes in electricity transmission that allow additional power generation to compete with our generation assets;
our ability to attract and retain qualified employees;
significant changes in our relationship with our employees, including the availability of qualified personnel, and the 
potential adverse effects if labor disputes or grievances were to occur;
changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits,
pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure under 
ERISA;
hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting 
from such hazards;
the impact of our obligations under the TRA;
our ability to optimize our assets through targeted investment in cost-effective technology enhancements and operations
performance initiatives;
our  ability  to  effectively  and  efficiently  plan,  prepare  for  and  execute  expected  asset  retirements  and  reclamation 
obligations and the impacts thereof;
our ability to successfully complete the integration of the businesses of Vistra Energy and Dynegy and our ability to
successfully capture the full amount of projected synergies relating to the Merger, and
actions by credit rating agencies.

Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we 
undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is
made or to reflect the occurrence of unanticipated events or circumstances.  New factors emerge from time to time, and it is not 
possible for us to predict them.  In addition, we may be unable to assess the impact of any such event or condition or the extent 
to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those
contained in or implied by any forward-looking statement.  As such, you should not unduly rely on such forward-looking statements.

83

INDUSTRY AND MARKET INFORMATION

Certain industry and market data and other statistical information used throughout this report are based on independent 
industry publications, government publications, reports by market research firms or other published independent sources, including
certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of states in which
we operate and NYMEX.  We did not commission any of these publications, reports or other sources.  Some data is also based on 
good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above.  
Industry publications, reports and other sources generally state that they have obtained information from sources believed to be
reliable, but do not guarantee the accuracy and completeness of such information.  While we believe that each of these studies,
publications, reports and other sources is reliable, we have not independently investigated or verified the information contained 
or referred to therein and make no representation as to the accuracy or completeness of such information.  Forecasts are particularly
likely to be inaccurate, especially over long periods of time, and we do not know what assumptions were used in preparing such
forecasts.  Statements regarding industry and market data and other statistical information used throughout this report involve
risks and uncertainties and are subject to change based on various factors.

84

Item 8. 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Vistra Energy Corp.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Vistra Energy Corp. and its subsidiaries (the "Company") as
of December 31, 2018 and 2017, and the related statements of consolidated income (loss), consolidated comprehensive income 
(loss), consolidated cash flows, and consolidated equity, for the years ended December 31, 2018 and 2017, for the period October 
3, 2016 through December 31, 2016 (Successor Company operations) and the period January 1, 2016 through October 2, 2016
(Predecessor Company operations), and the related notes (collectively referred to as the "financial statements"). In our opinion, 
the Successor Company financial statements present fairly, in all material respects, the financial position of the Company as of 
December 31, 2018 and 2017, and the results of its operations and its cash flows, for the years ended December 31, 2018 and 2017 
and for the period October 3, 2016 through December 31, 2016, in conformity with accounting principles generally accepted in
the United States of America. Further, in our opinion, the Predecessor Company financial statements present fairly, in all material 
respects, the results of operations and cash flows of the Predecessor Company for the period January 1, 2016 through October 2,
2016, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in 
Internal  Control  -  Integrated  Framework  (2013)  issued  by  the  Committee  of  Sponsoring  Organizations  of  the  Treadway
Commission and our report dated February 28, 2019, expressed an unqualified opinion on the Company's internal control over 
financial reporting.

Fresh-Start Reporting

As discussed in Note 6 to the financial statements, on August 29, 2016 the Bankruptcy Court entered an order confirming the plana
of reorganization which became effective on October 3, 2016. Accordingly, the accompanying financial statements have been 
prepared in conformity with Accounting Standards Codification Topic 852, Reorganizations, for the Successor Company as a new 
entity with assets, liabilities, and a capital structure having carrying values not comparable with prior periods as described in Note
1 to the financial statements.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on
the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company
Accounting  Oversight  Board  (United  States)  (PCAOB)  and  are  required  to  be  independent  with  respect  to  the  Company  in 
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the 
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error 
or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether 
due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Dallas, TX
February 28, 2019

We have served as the Company's auditor since 2002.

85

VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(Millions of Dollars, Except Per Share Amounts)

Year Ended December 31,

2018

2017

$

Operating revenues
Fuel, purchased power costs and delivery fees
Net gain from commodity hedging and trading activities
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Impairment of long-lived assets
Operating income (loss)

Other income (Note 23)
Other deductions (Note 23)
Interest expense and related charges (Note 11)
Impacts of Tax Receivable Agreement (Note 10)
Equity in earnings of unconsolidated investment (Note 23)
Reorganization items (Note 5)

Income (loss) before income taxes
Income tax (expense) benefit (Note 9)

Net income (loss)

Less: Net loss attributable to noncontrolling interest

Net loss attributable to Vistra Energy

$

Weighted average shares of common stock outstanding:

$

9,144
(5,036)
—
(1,297)
(1,394)
(926)
—
491
47
(5)
(572)
(79)
17
—
(101)
45
(56)
2
(54) $

Period from 
October 3, 2016 
through 
December 31, 2016
1,191
$
(720)
—
(208)
(216)
(208)
—
(161)
10
—
(60)
(22)
—
—
(233)
70
(163)
—
(163)

5,430
(2,935)
—
(973)
(699)
(600)
(25)
198
37
(5)
(193)
213
—
—
250
(504)
(254)
—
(254) $

Period from
January 1, 2016 
through 
October 2, 2016
3,973
$
(2,082)
282
(664)
(459)
(482)
—
568
19
(75)
(1,049)
—
—
22,121
21,584
1,267
22,851

Basic
Diluted

504,954,371
504,954,371

427,761,460
427,761,460

427,560,620
427,560,620

Net loss per weighted average share of common stock
outstanding:
Basic
Diluted

Dividend declared per share of common stock

See Notes to the Consolidated Financial Statements.

$
$
$

(0.11) $
(0.11) $
— $

(0.59) $
(0.59) $
— $

(0.38)
(0.38)
2.32

86

Predecessor

Period from
January 1, 2016 
through 
October 2, 2016
22,851
$

—
—

1
1
22,852

VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)

Net income (loss)
Other comprehensive income (loss), net of tax effects:

$

(56) $

Successor

Year Ended December 31,

2018

2017

Period from 
October 3, 2016 
through 
December 31, 2016
(163)

(254) $

Effects related to pension and other retirement benefit
obligations (net of tax (benefit) expense of $(2), $(6),
$3 and $—)

Adoption of new accounting standard (Note 1)
Other comprehensive income, net of tax effects —
cash flow hedges (net of tax benefit of $— in all
periods)

Total other comprehensive income (loss)
Comprehensive income (loss)
Less: Comprehensive loss attributable to noncontrolling
interest
Comprehensive loss attributable to Vistra Energy

See Notes to the Consolidated Financial Statements.

(6)
1

—
(5)
(61)

(23)
—

—
(23)
(277)

2
(59) $

—
(277) $

$

6
—

—
6
(157)

—
(157)

87

VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)

Cash flows — operating activities:

Net income (loss)
Adjustments to reconcile net income (loss) to cash
provided by (used in) operating activities:

Depreciation and amortization
Deferred income tax expense (benefit), net
Unrealized net (gain) loss from mark-to-market
valuations of commodities
Unrealized net (gain) loss from mark-to-market
valuations of interest rate swaps
Gain on extinguishment of liabilities subject to
compromise (Note 6)
Net loss from adopting fresh start reporting (Note 5)
Contract claims adjustments of Predecessor (Note 5)
Impairment of long-lived assets (Note 4)
Write-off of intangible and other assets (Note 23)
Impacts of Tax Receivable Agreement (Note 10)
Change in asset retirement obligation liability
Asset retirement obligation accretion expense
Stock-based compensation
Other, net

Changes in operating assets and liabilities:

Affiliate accounts receivable/payable — net
Accounts receivable — trade
Inventories
Accounts payable — trade
Commodity and other derivative contractual assets
and liabilities
Margin deposits, net
Accrued interest
Accrued taxes
Accrued employee incentive
Alcoa contract settlement (Note 4)
Tax Receivable Agreement payment (Note 10)
Major plant outage deferral
Other — net assets
Other — net liabilities

Cash provided by (used in) operating activities

Cash flows — financing activities:

Issuances of long-term debt (Note 14)
Repayments/repurchases of debt (Note 14)
Net borrowings under accounts receivable securitization
program (Note 13)
Debt tender offer and other debt financing fee
Stock repurchase (Note 16)

Successor

Year Ended December 31,

2018

2017

Period from
October 3, 2016
through
December 31, 2016

Predecessor

Period from
January 1, 2016
through
October 2, 2016

$

(56) $

(254) $

(163)

$

22,851

1,533
(62)

380

5

—
—
—
—
—
79
(27)
50
73
92

—
(207)
61
90

(80)
(221)
(105)
(64)
40
—
(16)
(22)
73
(145)
1,471

1,000
(3,075)

339
(236)
(763)

88

835
418

145

(29)

—
—
—
25
—
(213)
112
60
—
69

—
7
22
(30)

(1)
146
(10)
33
(24)
238
(26)
(66)
4
(75)
1,386

—
(191)

—
(8)
—

285
(76)

165

11

—
—
—
—
—
22
—
6
—
1

—
135
3
(79)

(48)
(193)
32
12
24
—
—
—
(2)
(54)
81

—
—

—
—
—

532
(1,270)

36

—

(24,344)
2,013
13
—
45
—
—
—
—
63

31
(216)
71
26

29
(124)
(10)
(13)
(30)
—
—
—
(3)
62
(238)

—
(2,655)

—
—
—

VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)

Successor

Year Ended December 31,

2018

2017

Incremental Term Loan B Facility (Note 14)
Special Dividend (Note 16)
Net proceeds from issuance of preferred stock (Note 5)
Payments to extinguish claims of TCEH first lien
creditors (Note 5)
Payment to extinguish claims of TCEH unsecured
creditors (Note 5)
Borrowings under TCEH DIP Roll Facilities and DIP
Facility (Note 14)
TCEH DIP Roll Facilities and DIP Facility financing
fees
Other, net

Cash provided by (used in) financing activities

Cash flows — investing activities:

Capital expenditures, including LTSA prepayments
Nuclear fuel purchases
Development and growth expenditures (Note 3)
Cash acquired in the Merger
Odessa acquisition (Note 3)
Lamar and Forney acquisition — net of cash acquired
(Note 3)
Changes in restricted cash (Predecessor)
Proceeds from sales of nuclear decommissioning trust
fund securities (Note 23)
Investments in nuclear decommissioning trust fund
securities (Note 23)
Notes/advances due from affiliates
Other, net

Cash used in investing activities

Net change in cash, cash equivalents and restricted cash
(Successor); Net change in cash and cash equivalents
(Predecessor)
Cash, cash equivalents and restricted cash — beginning
balance (Successor); Cash and cash equivalents —
beginning balance (Predecessor)
Cash, cash equivalents and restricted cash — ending
balance (Successor); Cash and cash equivalents — ending
balance (Predecessor)

See Notes to the Consolidated Financial Statements.

Period from
October 3, 2016
through
December 31, 2016
1,000
(992)
—

Predecessor

Period from
January 1, 2016
through
October 2, 2016
—
—
69

—

—

—

—
(2)
6

(48)
(41)
—
—
—

—
—

25

(30)
—
1
(93)

(6)

(486)

(429)

4,680

(112)
(8)
1,059

(230)
(33)
—
—
—

(1,343)
233

201

(215)
(41)
8
(1,420)

(599)

—
—
—

—

—

—

—
12
(2,723)

(378)
(118)
(34)
445
—

—
—

252

(274)
—
6
(101)

—
—
—

—

—

—

—
(2)
(201)

(114)
(62)
(190)
—
(355)

—
—

252

(272)
—
14
(727)

(1,353)

458

2,046

1,588

1,594

1,400

$

693

$

2,046

$

1,588

$

801

89

VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)

Year Ended December 31,

2018

2017

ASSETS

Current assets:

Cash and cash equivalents
Restricted cash (Note 23)
Trade accounts receivable — net (Note 23)
Inventories (Note 23)
Commodity and other derivative contractual assets (Note 18)
Margin deposits related to commodity contracts
Prepaid expense and other current assets

Total current assets
Restricted cash (Note 23)
Investments (Note 23)
Investment in unconsolidated subsidiary (Note 23)
Property, plant and equipment — net (Note 23)
Goodwill (Note 8)
Identifiable intangible assets — net (Note 8)
Commodity and other derivative contractual assets (Note 18)
Accumulated deferred income taxes (Note 9)
Other noncurrent assets
Total assets

LIABILITIES AND EQUITY

Current liabilities:

Accounts receivable securitization program (Note 13)
Long-term debt due currently (Note 14)
Trade accounts payable
Commodity and other derivative contractual liabilities (Note 18)
Margin deposits related to commodity contracts
Accrued taxes
Accrued taxes other than income
Accrued interest
Asset retirement obligations (Note 23)
Other current liabilities

Total current liabilities

Long-term debt, less amounts due currently (Note 14)
Commodity and other derivative contractual liabilities (Note 18)
Accumulated deferred income taxes (Note 9)
Tax Receivable Agreement obligation (Note 10)
Asset retirement obligations (Note 23)
Identifiable intangible liabilities — net (Note 8)
Other noncurrent liabilities and deferred credits (Note 23)

Total liabilities

90

$

$

$

$

$

$

636
57
1,087
412
730
361
152
3,435
—
1,250
131
14,612
2,068
2,493
109
1,336
590
26,024

339
191
945
1,376
4
10
182
77
156
345
3,625
10,874
270
10
420
2,217
401
340
18,157

1,487
59
582
253
190
30
72
2,673
500
1,240
—
4,820
1,907
2,530
58
710
162
14,600

—
44
473
224
4
58
136
16
99
297
1,351
4,379
102
—
333
1,837
36
220
8,258

VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)

Total equity (Note 16):

Common stock (par value — $0.01; number of shares authorized — 1,800,000,000)
(shares outstanding: December 31, 2018 — 493,215,309; December 31, 2017 —
428,398,802)
Additional paid-in-capital
Retained deficit
Accumulated other comprehensive income (loss)

Stockholders' equity

Noncontrolling interest in subsidiary

Total equity
Total liabilities and equity

See Notes to the Consolidated Financial Statements.

Year Ended December 31,

5
9,329
(1,449)
(22)
7,863
4
7,867
26,024

$

4
7,765
(1,410)
(17)
6,342
—
6,342
14,600

$

91

VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED EQUITY
(Millions of Dollars)

(Successor) /
Capital
Account
(Predecessor)

Additional
Paid-In
Capital
(Successor)

Retained
Deficit
(Successor)

Accumulated
Other
Comprehensive
Income (Loss)

Total
Stockholders'
Equity

Noncontrolling
Interests
(Successor)

Total
Equity

Equity in Successor:

Balances at October 3, 2016

$

Shares issued upon Emergence
Effects of stock-based
compensation
Other issuances of common stock
Net loss
Dividends declared on common
stock
Pension and OPEB liability —
change in funded status

— $ — $ — $
4

7,737

—

—
—
—

—

—

4
1
—

—

—

—
—
(163)

(992)

—

Balances at December 31, 2016

$

4

$ 7,742

$ (1,155) $

—
—

—
—

23
—

—
—

—
(254)

—
(1)

— $
—

— $

7,741

— $
—

—
7,741

—
—
—

—

6

6

—
—

(23)
—

4
1
(163)

(992)

6

—
—
—

—

—

4
1
(163)

(992)

6

$

6,597

$

— $ 6,597

23
(254)

(23)
(1)

—
—

—
—

23
(254)

(23)
(1)

Effects of stock-based
compensation
Net loss
Pension and OPEB liability —
change in funded status
Other

Balances at December 31, 2017
Stock and stock compensation
awards issued in connection with
the Merger
Treasury stock
Effects of stock-based
compensation
Tangible equity units acquired
Warrants acquired
Net loss
Adoption of new accounting
standards (Note 1)
Pension and OPEB liability —
change in funded status
Investment by noncontrolling
interest
Other

Balances at December 31, 2018

Membership interests in Predecessor:

Balances at December 31, 2015

Net income
Cash flow hedges — change
during period

Balances at October 2, 2016

$

4

$ 7,765

$ (1,410) $

(17) $

6,342

$

— $ 6,342

1
—

—
—
—
—

—

—

—
—

1,901
(778)

72
369
2
—

—

—

—
(2)

—
—

—
—
—
(54)

16

—

—
(1)

—
—

—
—
—
—

1

(6)

—
—

1,902
(778)

72
369
2
(54)

17

(6)

—
(3)

—
—

—
—
—
(2)

—

—

6
—

1,902
(778)

72
369
2
(56)

17

(6)

6
(3)

5

$ 9,329

$ (1,449) $

(22) $

7,863

$

4

$ 7,867

(22,851) $ — $ — $
—
22,851

—

(33) $ (22,884)
22,851
—

—

—

—

33

— $ — $ — $

— $

33

—

$

$

$

See Notes to the Consolidated Financial Statements.

92

VISTRA ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

References in this report to "we," "our," "us" and "the Company" are to Vistra Energy and/or its subsidiaries in the Successor 
period, and to TCEH and/or its subsidiaries in the Predecessor periods, as apparent in the context.  See Glossary for defined terms.

Vistra Energy is a holding company operating an integrated retail and generation business in markets throughout the U.S.  

Through our subsidiaries, we are engaged in competitive electricity market activities including power generation, wholesale energy
sales and purchases, commodity risk management and retail sales of electricity to end users.

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), 
(v) MISO and (vi) Asset Closure.  The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets
served by businesses acquired in the Merger.  See Note 22 for further information concerning reportable business segments.

On the Petition Date, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including the Debtors, 
filed voluntary petitions for relief under the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware.aa

On the Effective Date, subsidiaries of TCEH that were Debtors in the Chapter 11 Cases (the TCEH Debtors) and certain 
EFH Corp. subsidiaries (the Contributed EFH Debtors) completed their reorganization under the Bankruptcy Code and emerged 
from the Chapter 11 Cases as subsidiaries of a newly formed company, Vistra Energy (our Successor).  On the Effective Date, 
Vistra Energy was spun-off from EFH Corp. in a tax-free transaction to the former first lien creditors of TCEH (Spin-Off).  As a
result, as of the Effective Date, Vistra Energy is a holding company for subsidiaries principally engaged in competitive electricity 
market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales
of electricity to end users.  TCEH is the Predecessor to Vistra Energy.  See Note 5 for further discussion regarding the Chapter 11
Cases.

Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement.  Pursuant 
to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. 
Because the Merger closed on April 9, 2018, Vistra Energy's consolidated financial statements and the notes related thereto do not 
include the financial condition or the operating results of Dynegy prior to April 9, 2018.  See Note 2 for a summary of the Merger 
transaction and business combination accounting.

r

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 proceduresu
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.

tt

93

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.

f

The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited 
financial statements included in our annual report on Form 10-K for the year ended December 31, 2017, with the exception of the
changes in reportable segments as detailed above.  Adjustments (consisting of normal recurring accruals) necessary for a fair 
presentation of the results of operations and financial position have been included therein.  All intercompany items and transactions
have been eliminated in consolidation.  All dollar amounts in the financial statements and tables in the notes are stated in millions
of U.S. dollars unless otherwise indicated.

Use of Estimates

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

We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities utilizing 
instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks.  If the 
instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities,
changes in the fair value of the derivative are recognized in net income as unrealized gains and losses.  This recognition is referred 
to as mark-to-market accounting.  The fair values of our unsettled derivative instruments under mark-to-market accounting are
reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities.  We report derivative
assets  and  liabilities  in  the  consolidated  balance  sheets  without  taking  into  consideration  netting  arrangements  we  have  with
counterparties.  Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated 
balance sheets, except for certain margin amounts related to changes in fair value on  CME transactions that, beginning in January
2017, are legally characterized as settlement of derivative contracts rather than collateral.  When derivative instruments are settled 
and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities
are reversed.  See Notes 17 and 18 for additional information regarding fair value measurement and commodity and other derivative 
contractual assets and liabilities.  A commodity-related derivative contract may be designated as a normal purchase or sale if the 
commodity is to be physically received or delivered for use or sale in the normal course of business.  If designated as normal, the 
derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or 
income statement recognition of the contract until settlement.

Because  derivative  instruments  are  frequently  used  as  economic  hedges,  accounting  standards  related  to  derivative
instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash
flow or fair value hedges if certain conditions are met.  At December 31, 2018 and 2017, there were no derivative positions
accounted for as cash flow or fair value hedges.

For the Successor period, we report commodity hedging and trading results as revenue, fuel expense or purchased power in 
the statements of consolidated income (loss) depending on the type of activity.  Electricity hedges, financial natural gas hedges
and trading activities are primarily reported as revenue.  Physical or financial hedges for coal, diesel or uranium, along with
physical natural gas trades, are primarily reported as fuel expense.  For the Predecessor periods, all activity was reported as a net 
gain (loss) from commodity hedging and trading activities.  Realized and unrealized gains and losses associated with interest rate
swap transactions are reported in the statements of consolidated income (loss) in interest expense for both the Predecessor and
Successor.

94

Revenue Recognition

Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes
delivered or services provided. Sales tax is excluded from revenue.  Energy sales and services that have been delivered but not
billed by period end are estimated.  Accrued unbilled revenues are based on estimates of customer usage since the date of the last 
meter reading provided by the independent system operators or electric distribution companies.  Estimated amounts are adjusted 
when actual usage is known and billed.  See Note 7 for detailed descriptions of revenue from contracts with customers.

We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are not 
accounted for on a mark-to-market basis.  These revenues primarily consist of physical electricity sales to the ISO or RTO, ancillary
service revenue for reliability services, capacity revenue for making installed generation and demand response available for system
reliability requirements, and certain other electricity sales contracts.  See Note 7 for detailed descriptions of revenue from contracts
with customers.  See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts.

g

Advertising Expense

We expense advertising costs as incurred and include them within selling, general and administrative expenses.  Advertising
expenses totaled $46 million, $44 million, $9 million and $35 million for the Successor period for the year ended December 31, 
2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 
through October 2, 2016, respectively.

Impairment of Long-Lived Assets

We  evaluate  long-lived  assets  (including  intangible  assets  with  finite  lives)  for  impairment  whenever  indications  of 
impairment exist.  The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less
than the carrying value.  If there is such impairment, a loss would be recognized based on the amount by which the carrying value 
exceeds the fair value.  Fair value is determined primarily by discounted cash flows, supported by available market valuations, if 
applicable.

Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their estimated 
useful lives based on the expected realization of economic effects.  See Note 8 for details of intangible assets with indefinite lives,
including discussion of fair value determinations.

aa

Goodwill and Intangible Assets with Indefinite Lives

As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally 
allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization
value is allocated to goodwill (see Note 6).  We evaluate goodwill and intangible assets with indefinite lives for impairment at 
least annually, or when indications of impairment exist.  We have established October 1 as the date we evaluate goodwill and 
intangible assets with indefinite lives for impairment.  The Predecessor's annual evaluation date was December 1.  See Note 8 for 
details of goodwill, including discussion of fair value determinations.

ff

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 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.

95

Defined Benefit Pension Plans and OPEB Plans

On the Merger  Date, Vistra Energy assumed the pension and OPEB plans that Dynegy had provided to certain of its eligible
employees and retirees.  The excess of the benefit obligations over the fair value of plan assets was recognized as a liability.  See
Note 2 for additional information regarding the Merger.

On  the  Effective  Date,  EFH  Corp.  transferred  sponsorship  of  certain  employee  benefit  plans  (including  related  assets),
programs and policies to a subsidiary of Vistra Energy.  Certain health care and life insurance benefits are offered to eligible 
employees and their dependents upon the retirement of such employee from the company.  Pension benefits are offered to eligible
employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. 
Effective January 1, 2017, the OPEB plan was amended to discontinue the life insurance benefits for active employees.  Costs of
pension and OPEB plans are dependent upon numerous factors, assumptions and estimates.

Prior to the Effective Date, our Predecessor bore a portion of the costs of the EFH Corp. sponsored pension and OPEB plans

and accounted for the arrangement under multiple employer plan accounting.

See Note 19 for additional information regarding pension and OPEB plans.

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.  See Note 20 for additional information regarding stock-based compensation.

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

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 ana
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

On the Merger Date, Vistra Energy and Dynegy effected a merger transaction that for tax purposes was treated as a tax-free
reorganization in which Vistra Energy survived as the parent entity.  In general, all of Dynegy's tax basis and attributes were
transferred to Vistra Energy, including approximately $4.2 billion of utilizable NOLs and refundable AMT tax credits.

Prior to the Effective Date, EFH Corp. filed a consolidated U.S. federal income tax return that included the results of our 
Predecessor; however, our Predecessor's income tax expense and related balance sheet amounts were recorded as if it filed separate 
corporate income tax returns.

Investment tax credits are accounted for under the deferral method, which resulted in a reduction to the basis of the Upton 

2 solar facility of $78 million and a corresponding increase in the deferred tax assets in 2018.

Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as 

required under accounting rules.  See Note 9.

We report interest and penalties related to uncertain tax positions as current income tax expense.  See Note 9.

96

Tax Receivable Agreement

The Company accounts for its obligations under the Tax Receivable Agreement (TRA) as a liability in our consolidated 
balance sheets (see Note 10).  The carrying value of the TRA obligation represents the discounted amount of projected payments 
under the TRA.  The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate
income tax rate and (b) estimates of our taxable income in the current and future years.  Our taxable income takes into consideration 
the current federal tax code and reflects our current estimates of future results of the business.

The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective 
interest method and the interest rate estimated at the Emergence Date.  Changes in the estimated amount of this obligation resulting
from changes to either the timing or amount of TRA payments are recognized in the period of change and are included on our 
statement of consolidated income (loss) under the heading of Impacts of Tax Receivable Agreement.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies.  Accruals for loss contingencies
are recorded when management determines that it is probable that a liability has been incurred and that such economic loss can 
be reasonably estimated.  Such determinations are subject to interpretations of current facts and circumstances, forecasts of future 
events and estimates of the financial impacts of such events.  See Note 15 for a discussion of contingencies.

ff

Cash and Cash Equivalents

For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of 

three months or less are considered cash equivalents.

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes.  See Notes 14 and 23 for more details

regarding restricted cash.

Property, Plant and Equipment

In connection with fresh start reporting, carrying amounts of property, plant and equipment were adjusted to estimated fair 
values as of the Effective Date (see Note 6).  Property, plant and equipment added subsequent to the Effective Date has been 
recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual 
facilities developed (see Notes 2 and 3).  Significant improvements or additions to our property, plant and equipment that extend 
the life of the respective asset are capitalized at cost, while other costs are expensed when incurred.  The cost of self-constructed 
property additions includes materials and both direct and indirect labor, including payroll-related costs.  Interest related to qualifying 
construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization 
of interest cost.  See Note 11.

tt

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.  See Note 23.

Asset Retirement Obligations (ARO)

A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated 
with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is
incurred if a fair value is reasonably estimable.  At initial recognition of an ARO obligation, an offsetting asset is also recorded 
for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the 
asset.  These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining 
and removal of lignite/coal-fueled plant ash treatment facilities.  Over time, the liability is accreted for the change in present value
and the initial capitalized costs are depreciated over the remaining useful lives of the assets.  Generally, changes in estimates
related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. 
Changes in estimates related to assets that have been retired or for which capitalized costs are not recoverable are reflected in the
statements of consolidated income (loss).  See Note 23.

97

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.  See Note 23.

Investments

Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets.  
Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded 
at current market value.  See Note 23 for discussion of these and other investments.

Unconsolidated Investments

We use the equity method of accounting for investments in affiliates over which we exercise significant influence.  Our share 
of net income (loss) from these affiliates is recorded to equity in earnings (loss) of unconsolidated investment in the statements
of consolidated net income (loss). See Note 23.

Noncontrolling Interest

Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own.  EEI is our consolidated 
subsidiary that owns a coal facility in Joppa, Illinois.  This noncontrolling interest is classified as a component of equity separate 
from stockholders' equity in the consolidated balance sheets.

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded 
as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capital.  See Note 16.

Adoption of New Accounting Standards

Revenue from Contracts with Customers — On January 1, 2018, we adopted Accounting Standards Update (ASU) 2014-09,
Revenue from Contracts with Customers (Topic 606) and all related amendments (new revenue standard) using the modified 
retrospective method for all contracts outstanding at the time of adoption.  We recognized the cumulative effect of initially applying 
the new revenue standard as an adjustment to the opening balance of retained earnings.  The comparative information has not been 
restated and continues to be reported under the accounting standards in effect for those periods.  The impact of the adoption of 
the new revenue standard was immaterial and we expect the adoption to continue to be immaterial to our net income on an ongoing
basis.  Our retail energy charges and wholesale generation, capacity and contract revenues will continue to be recognized when 
electricity and other services are delivered to our customers.  The impact of adopting the new revenue standard primarily relates
to the deferral of acquisition costs associated with retail contracts with customers that were previously expensed as incurred.  Under 
the new revenue standard, these amounts are capitalized and amortized over the expected life of the customer.

aa

As of January 1, 2018, the cumulative effect of the changes made to our consolidated balance sheet for the adoption of the 

new revenue standard was as follows:

Impact on consolidated balance sheet:
Assets

Prepaid expense and other current assets
Accumulated deferred income taxes
Other noncurrent assets

Equity

Retained deficit

December 31,
2017

Adoption of New
Revenue Standard

January 1, 
2018

$
$
$

$

72
710
162

$
$
$

5
$
(4) $
$
16

77
706
178

(1,410) $

17

$

(1,393)

98

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

as follows:

Impact on statement of consolidated income (loss):

Operating revenues
Selling, general and administrative expenses
Net income (loss)

Impact on consolidated balance sheet:
Assets

Prepaid expense and other current assets
Accumulated deferred income taxes
Other noncurrent assets

Equity

Retained deficit

Year Ended December 31, 2018

As Reported

Amount Without
Adoption of New
Revenue Standard

Effect of Change 
Higher (Lower)

$

9,144
(926)
(56)

$

9,141
(939)
(68)

3
13
12

December 31, 2018

Balances Without
Adoption of New
Revenue Standard

Effect of Change 
Higher (Lower)

As Reported

$

152
1,336
590

$

145
1,349
559

(1,449) $

(1,478) $

7
(13)
31

29

$

$

$

See Note 7 for the disclosures required by the new revenue standard.

Statement of Cash Flows — 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.  We adopted the standard on January 1, 
2018.  The ASU modified our presentation of our statements of consolidated cash flows, and retrospective application to comparative
periods presented was required.  For the Successor period for the year ended December 31, 2017 and the period from October 3,
2016 through December 31, 2016, our statements of consolidated cash flows previously reflected a source of cash of $186 million
and $48 million, respectively, reported as changes in restricted cash that is now reported in net change in cash, cash equivalents
and restricted cash.  See the statements of consolidated cash flows and Note 23 for disclosures related to the adoption of this
accounting standard.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income — In February 2018, the FASB 
issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.  The ASU permits 
the reclassification of income tax effects of the Tax Cuts and Jobs Act on items within accumulated other comprehensive income 
(AOCI) to retained earnings.  We adopted this ASU in the fourth quarter of 2018, and the impact was additional tax expense to
AOCI of $1 million with the offset to retained earnings.

Changes to the Disclosure Requirements for Defined Benefit Plans — In August 2018, the FASB issued ASU 2018-14,
Changes to the Disclosure Requirements for Defined Benefit Plans.  The ASU removes disclosure requirements for (a) the amounts 
in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next 
fiscal year, (b) related party disclosures about the amount of future annual benefits covered by insurance and annuity contracts
and significant transactions between the employer or related parties and the plan and (c) the effects of a one-percentage-point
change in assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic benefit 
costs and benefit obligation for postretirement health care benefits.  The ASU requires new disclosures for (a) the weighted-average 
interest crediting rates for cash balance plans and other plans with promised interest crediting rates and (b) an explanation of the 
reasons for significant gains and losses related to changes in the benefit obligation for the period.  We adopted this ASU in thet
fourth quarter of 2018, and the updated disclosures are included in Note 19.

99

Leases — In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, Leases (ASU 2016-02), 
which was further amended through several updates issued by the FASB in 2018.  The ASU amends previous GAAP to require
lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements.  The ASU requires the
lessee to recognize a right-of-use asset and lease liability on the balance sheet for all leases.  Leases will be classified as finance 
and operating with classifications affecting the pattern and expense recognition in the income statement.

We adopted the new standard on January 1, 2019 using the modified retrospective approach.  The new standard provides a 
number of optional practical expedients in transition.  We have elected the practical expedient which permits us to not reassess 
our prior conclusion about lease classification and initial direct costs under the new standard.  We have also elected the practical 
expedient to not separate lease and non-lease components for all applicable asset classes.  We have also elected the short-term
lease recognition exemption for all leases that qualify.  On adoption, we currently expect to recognize additional liabilities within 
the range of approximately $230 million to $280 million, with corresponding right-of-use assets of the same amount based on the
present value of the remaining rental payments for existing leases.  The adoption of this standard will have an immaterial impact 
to beginning retained earnings and the statements of consolidated income (loss).

Changes in Accounting Standards

In August 2018, the FASB issued ASU 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement.  The
ASU will be effective for fiscal years beginning after December 15, 2019 and early adoption is permitted.  The ASU removes
disclosure requirements for (a) the reasons for transfers between Level 1 and Level 2, (b) the policy for timing of transfers between
levels and (c) the valuation processes for Level 3.  The ASU will require new disclosures around (a) the changes in unrealized 
gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the 
end of the reporting period and (b) the range and weighted average of significant unobservable inputs used to develop Level 3 fair 
value measurements.  We are currently evaluating the impact of this ASU on our disclosures.

ff

In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud 
Computing Arrangement That Is a Service Contract.  The ASU will be effective for fiscal years beginning after December 15,
2019 and early adoption is permitted.  The ASU requires a customer in a cloud hosting arrangement that is a service contract to
determine which implementation costs to capitalize and which costs to expense based on the project stage of the implementation. 
The ASU also requires the customer to expense the capitalized implementation costs over the term of the hosting arrangement.  
The customer is required to apply the existing impairment and abandonment guidance on the capitalized implementation costs.  
We are currently evaluating the impact of this ASU on our financial statements.

2.  MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING

On the Merger Date, Vistra Energy and Dynegy, completed the transactions contemplated by the Merger Agreement.  Pursuant 
to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation.  
The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code, as amended, so that none of Vistra
Energy,  Dynegy  or  any  of  the  Dynegy  stockholders  will  recognize  any  gain  or  loss  in  the  transaction,  except  that  Dynegy 
stockholders could recognize a gain or loss with respect to cash received in lieu of fractional shares of Vistra Energy's common
stock. Vistra Energy is the acquirer for both federal tax and accounting purposes.

At the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other 
than  shares  owned  by Vistra  Energy  or  its  subsidiaries,  held  in  treasury  by  Dynegy  or  held  by  a  subsidiary  of  Dynegy,  was 
automatically converted into 0.652 shares of common stock, par value $0.01 per share, of Vistra Energy (the Exchange Ratio), 
except that cash was paid in lieu of fractional shares, which resulted in Vistra Energy issuing 94,409,573 shares of Vistra Energy 
common stock to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible equity units
and warrants.  The total number of Vistra Energy shares outstanding at the close of the Merger was 522,932,453 shares.  Dynegy
stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted 
upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra Energy's common 
stock, after giving effect to the Exchange Ratio.

100

Business Combination Accounting

We believe the Merger provides significant potential strategic benefits and opportunities to Vistra Energy, including increased
scale and market diversification, rebalanced asset portfolio and improved earnings and cash flow.  The Merger is being accounted 
for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed 
recorded at their estimated fair values on the Merger Date.  The combined results of operations are reported in our consolidated 
financial statements beginning as of the Merger Date.  A summary of the techniques used to estimate the preliminary fair value 
of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 17), is listed below:

•  Working capital was valued using available market information (Level 2).
•  Acquired property, plant and equipment was valued using a combination of an income approach and a market approach. 
The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).

•  Acquired derivatives were valued using the methods described in Note 17 (Level 1, Level 2 or Level 3).
•  Contracts with terms that were not at current market prices were also valued using a discounted cash flow analysis 
(Level 3).  The cash flows generated by the contracts were compared with their cash flows based on current market 
prices with the resulting difference discounted to present value and recorded as either an intangible asset or liability.

•  Long-term debt was valued using a market approach (Level 2).
•  AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).

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

Dynegy shares outstanding as of April 9, 2018 (in millions)
Exchange Ratio
Vistra Energy shares issued for Dynegy shares outstanding (in millions)
Opening price of Vistra Energy common stock on April 9, 2018
Purchase price for common stock
Fair value of equity component of tangible equity units
Fair value of outstanding stock compensation awards attributable to pre-combination service
Fair value of outstanding warrants
Total purchase price

144.8
0.652
94.4
19.87
1,876
369
26
2
2,273

$
$
$
$
$
$

101

Preliminary Purchase Price Allocation

Cash and cash equivalents
Trade accounts receivables, inventories, prepaid expenses and other current assets
Property, plant and equipment
Accumulated deferred income taxes
Identifiable intangible assets
Goodwill
Other noncurrent assets
Total assets acquired

Trade accounts payable and other current liabilities
Commodity and other derivative contractual assets and liabilities, net
Asset retirement obligations, including amounts due currently
Long-term debt, including amounts due currently
Other noncurrent liabilities
Total liabilities assumed

Identifiable net assets acquired
Noncontrolling interest in subsidiary

Total purchase price

$

$

445
856
10,520
492
351
161
423
13,248
687
422
477
8,920
464
10,970
2,278
5
2,273

Acquisition costs incurred in the Merger totaled $25 million for the year ended December 31, 2018.  For the period from
the Merger Date through December 31, 2018, our statements of consolidated income (loss) include revenues and net income (loss) 
acquired in the Merger totaling $3.902 billion and $224 million respectively.

Unaudited Pro Forma Financial Information —  The following unaudited pro forma financial information for the year 
ended December 31, 2018 and 2017 assumes that the Merger occurred on January 1, 2017.  The unaudited pro forma financial
information is provided for information purposes only and is not necessarily indicative of the results of operations that would have 
occurred had the Merger been completed on January 1, 2017, nor is the unaudited pro forma financial information indicative of 
future results of operations, which may differ materially from the pro forma financial information presented here.

d

Revenues

Net loss

Net loss attributable to Vistra Energy
Net loss attributable to Vistra Energy per weighted average share of common stock
outstanding — basic
Net loss attributable to Vistra Energy per weighted average share of common stock
outstanding — diluted

Year Ended December 31,

2018

2017

10,595

$
(268) $
(265) $

10,509
(969)
(983)

(0.52) $

(1.83)

(0.52) $

(1.83)

$

$

$

$

$

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

102

3.  ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES

Battery Energy Storage Projects (Successor)

We have completed the construction of our first battery energy storage system.  In October 2018, we were awarded a $1 
million grant from the TCEQ for our battery energy storage system at Upton 2 solar facility.  The grant is part of the Texas Emissions
Reduction Plan.  The 10 MW lithium-ion energy storage system will capture excess solar energy produced during the day and 
releases the energy in late afternoon and early evening, when demand is highest.  The project became operational on December 
31, 2018.

In June 2018, we announced that we will enter into a 20-year resource adequacy contract with Pacific Gas and Electric
Company (PG&E) to develop a 300 MW battery energy storage project at our Moss Landing Power Plant site in California.  PG&E 
filed its application with the California Public Utilities Commission (CPUC) in June 2018 and the CPUC approved the contract 
in November 2018.  We anticipate the battery storage project will enter commercial operations by the fourth quarter of 2020.

Odessa Acquisition (Successor)

In August 2017, La Frontera Holdings, LLC (La Frontera), an indirect wholly owned subsidiary of Vistra Energy, purchased 
a 1,054 MW CCGT natural gas-fueled generation plant (and other related assets and liabilities) located in Odessa, Texas (Odessa
Facility) from Odessa-Ector Power Partners, L.P., an indirect wholly owned subsidiary of Koch Ag & Energy Solutions, LLC 
(Koch) (altogether, the Odessa Acquisition).  La Frontera paid an aggregate purchase price of approximately $355 million, plus
a five-year earn-out provision, to acquire the Odessa Facility.  The purchase price was funded by cash on hand.

The Odessa Acquisition was accounted for as an asset acquisition.  Substantially all of the approximately $355 million
purchase price was assigned to property, plant and equipment in our consolidated balance sheet.  Additionally, the initial fair value 
associated with an earn-out provision of approximately $16 million was included as consideration in the overall purchase price. 
The earn-out provision requires cash payments to be made to Koch if spark-spreads related to the pricing point of the Odessa 
Facility exceed certain thresholds.  Subsequent to the acquisition, the earn-out provision has been accounted for as a derivative 
in our consolidated financial statements.  Partial buybacks of the earn-out provision were settled in February and May 2018.

r

Upton 2 Solar Development (Successor)

In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation 
facility in Upton County, Texas (Upton 2).  As part of this project, we entered a turnkey engineering, procurement and construction 
agreement to construct the approximately 180 MW facility.  During 2017 and 2018, we spent approximately $231 million related 
to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition 
of the development rights.  The facility began test operations in March 2018 and commercial operations began in June 2018.

Lamar and Forney Acquisition (Predecessor)

In April 2016, Luminant purchased all of the membership interests in La Frontera, the indirect owner of two combined-cycle
gas turbine (CCGT) natural gas-fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from a
subsidiary  of  NextEra  Energy,  Inc.  (the  Lamar  and  Forney Acquisition).    The  aggregate  purchase  price  was  approximately
$1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La
Frontera at closing, plus approximately $236 million for cash and net working capital.  The purchase price was funded by cash-
on-hand and additional borrowings under our Predecessor's DIP Facility totaling $1.1 billion.  After completing the acquisition, 
we repaid approximately $230 million of borrowings under our Predecessor's DIP Revolving Credit Facility primarily utilizing 
cash acquired in the transaction.  La Frontera and its subsidiaries were subsidiary guarantors under our Predecessor's DIP Roll
Facilities and, on the Effective Date, became subsidiary guarantors under the Vistra Operations Credit Facilities (see Note 14).

Predecessor Purchase Accounting — The Lamar and Forney Acquisition was accounted for in accordance with ASC 805, 
Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values
on the acquisition date.

g

103

To fair value the acquired property, plant and equipment, we used a discounted cash flow analysis, classified as Level 3 
within the fair value hierarchy levels (see Note 17).  This discounted cash flow model was created for each generation facility
based on its remaining useful life.  The discounted cash flow model included gross margin forecasts for each power generation
facility  determined  using  forward  commodity  market  prices  obtained  from  long-term  forecasts.   We  also  used  management's
forecasts of generation output, operations and maintenance expense, SG&A and capital expenditures.  The resulting cash flows, 
estimated based upon the age of the assets, efficiency, location and useful life, were then discounted using plant specific discount 
rates of approximately 9%.

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
Net working capital adjustments
Consideration paid to seller
Cash paid to repay project financing at close
Total cash paid related to acquisition

Cash and cash equivalents
Property, plant and equipment — net
Commodity and other derivative contractual assets
Other assets

Total assets acquired

Commodity and other derivative contractual liabilities
Trade accounts payable and other liabilities

Total liabilities assumed

Identifiable net assets acquired

$

$
$

$

603
(4)
599
950
1,549
210
1,316
47
44
1,617
53
15
68
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.

Unaudited  Pro  Forma  Financial  Information  —  The  following  unaudited  pro  forma  financial  information  for  the
Predecessor period from January 1, 2016 through October 2, 2016 assumes that the Lamar and Forney Acquisition occurred on 
January 1, 2016.  The unaudited pro forma financial information is provided for information purposes only and is not necessarily
indicative of the results of operations that would have occurred had the Lamar and Forney Acquisition been completed on January
1, 2016, nor is the unaudited pro forma financial information indicative of future results of operations.

Revenues

Net income (loss)

Predecessor

Period from
January 1, 2016
through
October 2, 2016
4,116
$

$

22,835

The unaudited pro forma financial information includes adjustments for incremental depreciation as a result of the fair value 

determination of the net assets acquired and interest expense on borrowings under our Predecessor's DIP Roll Facilities.

104

4.  RETIREMENT OF GENERATION FACILITIES

In August 2018, we filed a notice of suspension of operation with PJM and other mandatory regulatory notifications related 
to the retirement of our 51 MW Northeastern waste coal facility in McAddo, Pennsylvania.  We decided to retire this facility due 
to its uneconomic operations and financial outlook.  Following the receipt of regulatory approvals, the facility was retired in
October 2018.  The decision to retire this facility did not result in a material impact to the financial statements, and the operational
results of this facility are included in our Asset Closure segment.

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

Name

Killen

Stuart

Total

Location
Manchester, Ohio

Aberdeen, Ohio

Fuel Type
Coal

Coal

Net Generation
Capacity (MW)

204

679

883

Ownership
Interest
33%

39%

Date Units Taken Offline
May 31, 2018

May 24, 2018

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

Name
Monticello

Sandow

Location (all in the
state of Texas)

Titus County

Milam County

Fuel Type
Lignite/Coal

Lignite

Big Brown

Freestone County

Lignite/Coal

Total

Installed Nameplate
Generation
Capacity (MW)

1,880

1,137

1,150

4,167

Number
of Units
3

2

2

7

Date Units Taken Offline
January 4, 2018

January 11, 2018

February 12, 2018

In September and October 2017, we decided to retire our Monticello, Sandow and Big Brown plants and a related mine
which supplies the Sandow plants.  Management had previously announced its decisions to retire mines which supply the Monticello
and Big Brown plants.  The Monticello and Sandow plants were retired in January and the Big Brown plant in February 2018.  
We recorded a charge of approximately $206 million in 2017 related to the retirements, including employee-related severance 
costs, non-cash charges for writing off materials inventory and capitalized improvements and changes to the timing and amounts
of asset retirement obligations for mining and plant-related reclamation at these facilities.  The charge, all of which related to our 
Asset Closure segment, was recorded to operating costs and impairment of long-lived assets in our statements of consolidated 
income (loss).  In addition, we will continue the ongoing reclamation work at the plants' mines.

d

In October 2017, the Company and Alcoa entered into a contract termination agreement pursuant to which the parties agreed 
to an early settlement of a long-standing power and mining agreement.  In consideration for the early termination, Alcoa made a
payment to Luminant of approximately $238 million in October 2017.  The contract termination and related payment did not result
in a material gain or loss.  The contract had been important to the overall economic viability of the Sandow plant.

Regulatory Review — As part of the retirement process, Luminant filed notices with ERCOT, which triggered a reliability
review regarding such proposed retirements.  In October and November 2017, ERCOT determined the units were not needed for 
reliability, and the units were taken offline in January and February 2018.

105

5.  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.

n
t

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.

tt

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.

a

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 VistraVV
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.

106

Pre-Petition Claims

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

m

Predecessor Reorganization Items

Expenses and income directly associated with the Chapter 11 Cases are reported separately in the statements of consolidated 
income (loss) as reorganization items as required by ASC 852, Reorganizations.  Reorganization items also included adjustments
to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments were determined.  The following
table presents reorganization items incurred in the Predecessor period from January 1, 2016 through October 2, 2016 as reported
in the statements of consolidated income (loss):

Predecessor

Period from
January 1, 2016
through
October 2, 2016
$

(24,252)
2,013
55
39
13
11
(22,121)

$

Gain on reorganization adjustments (Note 6)
Loss from the adoption of fresh start reporting
Expenses related to legal advisory and representation services
Expenses related to other professional consulting and advisory services
Contract claims adjustments
Other

Total reorganization items

107

6. 

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.

- - 

n

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 annualn
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

Cash excluded from business enterprise value

Deferred asset related to prepaid capital lease obligation

Current liabilities, excluding short-term portion of debt and capital leases

Noncurrent, non-interest bearing liabilities
Vistra Energy reorganization value of assets

$

$

10,500

1,594

38

1,123

1,906
15,161

108

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.

TCEH
(Predecessor) (1)

Reorganization 
Adjustments (2)

Fresh Start
Adjustments

Vistra Energy
(Successor)

ASSETS
Current assets:

Cash and cash equivalents
Restricted cash
Trade accounts receivable — net
Advances to parents and affiliates of
Predecessor
Inventories
Commodity and other derivative
contractual assets
Margin deposits related to commodity
contracts
Other current assets

Total current assets

Restricted cash
Advance to parent and affiliates of
Predecessor
Investments
Property, plant and equipment — net
Goodwill
Identifiable intangible assets — net
Commodity and other derivative contractual
assets
Deferred income taxes
Other noncurrent assets
Total assets

LIABILITIES AND EQUITY
Current liabilities:

Long-term debt due currently
Trade accounts payable
Trade accounts and other payables to
affiliates of Predecessor
Commodity and other derivative
contractual liabilities
Margin deposits related to commodity
contracts
Accrued income taxes
Accrued taxes other than income
Accrued interest
Other current liabilities

Total current liabilities

$

$

1,829
12
750

(3)
(4)

(1,028)
131
4

$

(78)
—

—

—
17
(954)
—

(21)
1
53
—
4

—
320
38
(559)

(5)

5
145

(6)

(152)

(6)

—

—

12
4
(109)
170
75

(7)
(8)

$

$

$

$

78
374

255

42
47
3,387
650

17
1,038
10,359
152
1,148

73
—
51
16,875

4
402

152

125

64

12
119
110
243
1,231

$

$

109

$

$

$

(17)

—
—
—

—
(86)

—

—
3
(83)
—

4
9
(5,970)
1,755
2,256

(14)
730
158
(1,155)

(18)
(19)
(27)
(20)

(21)
(22)

(1)
3

—

—

—

—
—
—
5
7

801
143
754

—
288

255

42
67
2,350
650

—
1,048
4,442
1,907
3,408

59
1,050
247
15,161

8
550

—

125

64

24
123
1
418
1,313

TCEH
(Predecessor) (1)

Reorganization 
Adjustments (2)

Fresh Start
Adjustments

Vistra Energy
(Successor)

Long-term debt, less amounts due currently
Borrowings under debtor-in-possession
credit facilities
Liabilities subject to compromise
Commodity and other derivative contractual
liabilities
Deferred income taxes
Tax Receivable Agreement obligation
Asset retirement obligations
Other noncurrent liabilities and deferred
credits

Total liabilities

Equity:

Common stock
Additional paid-in-capital
Accumulated other comprehensive
income (loss)
Predecessor membership interests

Total equity

Total liabilities and equity

$

—

3,476

(9)

151

(23)

3,627

3,387
33,749

(3,387)
(33,749)

(9)
(10)

5
256
—
809

—
(256)
574
—

(11)
(12)

1,018
40,455

(13)

117
(33,150)

—
—

4
7,737

(14)
(15)

—
—

3
—
—
854

(900)
115

—
—

(24)

(25)

(32)
(23,548)
(23,580)
16,875

$

(16)

22
24,828
32,591
(559)

$

(26)
(26)

10
(1,280)
(1,270)
(1,155)

$

—
—

8
—
574
1,663

235
7,420

4
7,737

—
—
7,741
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
Addition of cash balances from the Contributed EFH Debtors
Payments to TCEH first lien creditors, including adequate protection
Payment to TCEH unsecured creditors (including $73 million to escrow)
Payment of administrative claims to TCEH creditors
Payment of legal fees, professional fees and other costs (including $52 million to escrow)

Net use of cash

$

$

69
22
(486)
(502)
(53)
(78)
(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.

110

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

Date.

(8)  Primarily reflects the following:

•  Reclassification of $82 million from LSTC related to secured and unsecured claims and $16 million in accrued professional 

fees from accounts payable to other current liabilities.

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

•  Payment of $12 million in professional fees. 

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

(10)  Reflects the elimination of TCEH's liabilities subject to compromise pursuant to the Plan of Reorganization (see Note 5). 

Liabilities subject to compromise were settled as follows in accordance with the Plan of Reorganization:

Notes, loans and other debt
Accrued interest on notes, loans and other debt
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements
Trade accounts payable and other expected allowed claims
Third-party liabilities subject to compromise
LSTC from the Contributed EFH Entities
Total liabilities subject to compromise
Fair value of equity issued to TCEH first lien creditors
TRA Rights issued to TCEH first lien creditors
Cash distributed and accruals for TCEH first lien creditors
Cash distributed for TCEH unsecured claims
Cash distributed and accruals for TCEH administrative claims
Settlement of affiliate balances
Net liabilities of contributed entities and other items
Gain on extinguishment of LSTC

$

$

31,668
646
1,243
192
33,749
8
33,757
(7,741)
(574)
(377)
(502)
(60)
(99)
(60)
24,344

(11)  Reflects the deferred income tax impact of the Plan of Reorganization implementation, including cancellation of debts and 

adjustment of tax basis of certain assets of PrefCo.

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

assumptions.

(13)  Primarily reflects the following:

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

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

(14)  Reflects the issuance of approximately 427,500,000 shares of Vistra Energy common stock, par value of $0.01 per share, to

the TCEH first lien creditors.  See Note 16.

111

(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
Vistra Operations Credit Facility – Initial Term Loan B Facility
Vistra Operations Credit Facility – Term Loan C Facility
Accrual for post-Emergence claims satisfaction
Tax Receivable Agreement obligation
Preferred stock of PrefCo
Other items
Cash and cash equivalents
Restricted cash

Equity value at Emergence

Common stock at par value
Additional paid-in capital

Equity value
Shares outstanding at October 3, 2016 (in millions)
Per share value

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

Gain on extinguishment of LSTC
Elimination of accumulated other comprehensive income
Change in control payments
Professional fees
Other items
Pretax gain on reorganization adjustments (Note 5)
Deferred tax impact of the Plan of Reorganization and Spin-off

Total impact to membership interests

Fresh start adjustments

$

$

$

$

$

$

$

10,500
(2,871)
(655)
(181)
(574)
(70)
(2)
801
793
7,741

4
7,737
7,741
427.5
18.11

24,344
(22)
(23)
(33)
(14)
24,252
576
24,828

(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
Generation plants and mining assets

Land

Nuclear Fuel

Other equipment
Total

Adjustment

Fair Value

$

$

(6,057) $
140
(23)
(30)
(5,970) $

3,698

490

157

97
4,442

112

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

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

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

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

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

and debt issuance costs.

(22)  Primarily reflects the following:

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

•  Adjustment to remove $26 million of unamortized debt issuance costs to reflect the Vistra Operations Credit Facilities 

at fair market value.

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

market prices of the facilities.

(24)  Increase in fair value of asset retirement obligation related to the plant retirement, mining and reclamation retirement, and 

coal combustion residuals.  See Note 23 for further discussion of our asset retirement obligations.

(25)  Reflects the following:

•  Reduction in fair value of unfavorable contracts related to wholesale contracts and a portion of an electricity supply 

contract in the amount of $476 million.  See footnote (20) above for further detail.

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

• 

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

• 

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

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

Reorganization.

113

(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
Add: Fair value of liabilities excluded from enterprise value
Less: Fair value of tangible assets
Less: Fair value of identified intangible assets

Vistra Energy goodwill

7.  REVENUE

The following tables disaggregate our revenue by major source:

$

$

10,500
3,030
(8,215)
(3,408)
1,907

Retail

ERCOT

PJM

NY/NE

MISO

Asset
Closure

CAISO/

Eliminations Consolidated

Year Ended December 31, 2018

$ 4,426

$ — $ — $ — $ — $ — $

— $

4,426

Revenue from contracts with
customers:

Retail energy charge in ERCOT
Retail energy charge in Northeast/
Midwest
Wholesale generation revenue
from ISO/RTO
Capacity revenue
Revenue from other wholesale
contracts

Total revenue from contracts
with customers

Other revenues:

1,123

—

— 1,151
—
—

—

214

—

792
369

29

5,549

1,365

1,190

Intangible amortization
Hedging and other revenues (a)
Affiliate sales

Total other revenues
Total revenues

(1)
(26)
(362)
74
— 1,632
1,269
48
$ 2,634
$ 5,597

2
(62)
595
535
$ 1,725

$

—

544
240

42

826

(9)
(41)
41
(9)
817

—

420
53

133

606

—

52
6

—

58

—

167
30

6

203

(9)
(195)
318
114
720

$

$

—
(31)
23
(8)
50

$

—
7
(2,609)
(2,602)
(2,399) $

1,123

3,126
698

424

9,797

(43)
(610)
—
(653)
9,144

____________
(a) 

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

Retail Energy Charges

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

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

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

114

Wholesale Generation Revenue from ISOs/RTOs

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

Capacity Revenue

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

Revenue from Other Wholesale Contracts

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

Other Revenues

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

mm

Contract and Other Customer Acquisition Costs

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

tt

Practical Expedients

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

115

Performance Obligations

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

Accounts Receivable

The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts

with customers and other activities:

Trade accounts receivable from contracts with customers — net
Other trade accounts receivable — net
Total trade accounts receivable — net

December 31, 2018
951
$
136
1,087

$

116

8.  GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

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

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

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:

December 31, 2018

December 31, 2017

Identifiable Intangible Asset
Retail customer relationship
Software and other technology-related assets
Retail and wholesale contracts
Contractual service agreements
Other identifiable intangible assets (a)

Total identifiable intangible assets subject to

amortization

Retail trade names (not subject to amortization)
Mineral interests (not currently subject to
amortization)

Total identifiable intangible assets

Gross
Carrying
Amount
1,680
$
270
316
70
42

Accumulated
Amortization
876
$
105
138
—
15

$

2,378

$

1,134

Net

804
165
178
70
27

1,244
1,245

4
2,493

$

$

____________
(a) 

Includes mining development costs and environmental allowances and credits.

Identifiable intangible liabilities are comprised of the following:

Gross
Carrying
Amount
1,648
$
183
154
—
33

Accumulated
Amortization
572
$
47
87
—
11

$

2,018

$

717

Net

1,076
136
67
—
22

1,301
1,225

4
2,530

$

$

Identifiable Intangible Liability
Contractual service agreements
Purchase and sale contracts
Environmental allowances

Total identifiable intangible liabilities

2018

2017

$

$
$

136
195
70
401

$

$
$

—
36
—
36

117

Amortization expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the 

statements of consolidated income (loss)) consisted of:

Identifiable Intangible 
Assets and Liabilities
Retail customer
relationship
Software and other
technology-related
assets
Retail and wholesale
contracts/purchase
and sale contracts
Other identifiable
intangible assets

Statements of Consolidated 
Income (Loss) Line

Depreciation and
amortization
Depreciation and
amortization

Operating revenues/fuel,
purchased power costs and
delivery fees
Operating revenues/fuel,
purchased power costs and
delivery fees/depreciation
and amortization

Successor

Remaining useful 
lives of identifiable
intangible assets at 
December 31, 
2018 (weighted 
average in years)

Year Ended December 31,

2018

2017

Period from 
October 3, 
2016
through 
December 31, 
2016

Predecessor

Period from 
January 1, 
2016
through 
October 2, 
2016

4

3

4

4

$

304

$

420

$

152

$

62

43

58

38

59

15

9

38

4

9

44

—

6

59

Total amortization expense (a)

$

467

$

532

$

203

$

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

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

r

•

•

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

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

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

118

Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of December 31, 2018, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for 

each of the next five fiscal years is as shown below.

Estimated Amortization Expense
299
$
201
$
154
$
91
$
67
$

Year
2019
2020
2021
2022
2023

9. 

INCOME TAXES

Successor

Vistra Energy files a United States federal income tax return that includes the results of its consolidated subsidiaries.  Vistra 
Energy is the corporate parent of the Vistra Energy consolidated group.  Pursuant to applicable United States Treasury regulations 
and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the 
taxes of such group.

t

tt

Predecessor

Prior to the Effective Date, EFH Corp. was the corporate parent of the EFH Corp. consolidated group, while TCEH and the 
Contributed EFH Debtors were classified as disregarded entities for U.S. federal income tax purposes.  For the 2016 tax year 
(through the period until the Effective Date) EFH Corp. filed a U.S. federal income tax return in October 2017 that included the 
results of TCEH and the EFH Contributed Debtors.  Pursuant to applicable U.S. Treasury regulations and published guidance of 
the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including TCEH and the Contributed EFH Debtors) 
were parties to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate 
member or disregarded entity in the EFH Corp. group was required to make payments to EFH Corp. in an amount calculated to
approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return.  Pursuant to thet
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.

119

Income Tax Expense (Benefit)

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

Current:

U.S. Federal
State

Total current

Deferred:

U.S. Federal
State

Total deferred
Total

Successor

Year Ended December 31,

2018

2017

Period from
October 3, 2016
through
December 31, 2016

Predecessor

Period from
January 1, 2016
through
October 2, 2016

$

$

(13)
30
17

(8)
(54)
(62)
(45)

$

$

72
14
86

417
1
418
504

$

$

— $

6
6

(75)
(1)
(76)
(70)

$

(6)
9
3

(1,234)
(36)
(1,270)
(1,267)

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

Period from 
October 3, 2016 
through 
December 31, 2016
(233)
$
35%
(82)
5
3
—
—

—

—
—
—
—
2
—
—
—
2
(70)
30.0%

$

$

Predecessor

Period from
January 1, 2016
through
October 2, 2016
$

21,584

35 %

7,554
—
(21)
—
—

—

—
—
—
—
38
12
(8,593)
(210)
(47)
(1,267)

(5.9)%

Income (loss) before income taxes
US federal statutory rate
Income taxes at the U.S. federal statutory rate

Nondeductible TRA accretion
State tax, net of federal benefit
Impacts of tax reform legislation on deferred taxes
Return to provision adjustment
Remeasurement of historical Vistra Energy deferred
taxes for expanded state footprint
Effect of refundable minimum tax credits no longer
subject to sequestration
Nondeductible compensation
Nondeductible transaction costs
Equity awards
Nondeductible debt restructuring costs
Nondeductible interest expense
Nontaxable gain on extinguishment of LSTC
Valuation allowance on state NOLs
Other

Income tax expense (benefit)
Effective tax rate

$

$

Successor

Year Ended December 31,

2018

2017

$

$

(101)
21%
(20)
8
22
—
(12)

(54)

(15)
8
3
(3)
—
—
—
20
(2)
(45)
44.6%

250

35%
88
(80)
13
451
19

—

—
—
—
—
—
—
—
—
13
504
201.6%

120

Deferred Income Tax Balances

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

as follows:

Noncurrent Deferred Income Tax Assets

Tax credit carryforwards
Loss carryforwards
Property, plant and equipment
Identifiable intangible assets
Long-term debt
Employee benefit obligations
Commodity contracts and interest rate swaps
Other

Total deferred tax assets

Noncurrent Deferred Income Tax Liabilities

Property, plant and equipment
Total deferred tax liabilities

Valuation allowance

Net Deferred Income Tax Asset

December 31,

2018

2017

$

$

$

76
958
—
184
188
109
212
40
1,767

406
406
35
1,326

$

$

$

—
—
520
81
20
56
25
8
710

—
—
—
710

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

f

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

The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax

asset of $2 million at December 31, 2018 and a net deferred tax liability of $6 million at December 31, 2017.

121

Liability for Uncertain Tax Positions

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

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

Successor

Year Ended December 31,

2018

2017

Period from
October 3, 2016
through
December 31, 2016

Predecessor

Period from
January 1, 2016
through
October 2, 2016

Balance at beginning of period, excluding interest and
penalties

Additions allocated in the Merger

Reductions based on tax positions related to prior years

Settlements with taxing authorities

Balance at end of period, excluding interest and penalties

$

$

— $

— $

— $

39
—

—

39

—
—

—

—
—

—

$

— $

— $

36

—
(1)
(35)
—

—

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

ff

—

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

122

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.

t

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.

10.  TAX RECEIVABLE AGREEMENT OBLIGATION

On the Effective Date, Vistra Energy entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of 
certain former first lien creditors of our Predecessor.  The TRA generally provides for the payment by us to holders of TRA Rights
of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a
result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our u
assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition 
of two CCGT natural gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be 
paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.

Pursuant to the TRA, we issued the TRA Rights for the benefit of the first lien secured creditors of our Predecessor entitled 
to receive such TRA Rights under the Plan of Reorganization.  Such TRA Rights are entitled to certain registration rights more 
fully described in the Registration Rights Agreement (see Note 21).

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

123

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

Year Ended December 31,

2018

2017

TRA obligation at the beginning of the period

$

Accretion expense

Payments

Changes in tax assumptions impacting timing of payments

Revaluation due to tax reform legislation
TRA obligation at the end of the period

Less amounts due currently

$

357
65
(16)
14

—

420

—

Noncurrent TRA obligation at the end of the period

$

420

$

596
82
(26)
(62)
(233)
357
(24)
333

Period from
October 3, 2016
through
December 31, 2016
574
$
22

—

—

—

596

—

596

$

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

a

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

124

11. 

INTEREST EXPENSE AND RELATED CHARGES

Successor

Year Ended December 31,

2018

2017

Interest paid/accrued post-Emergence
Interest paid/accrued on debtor-in-possession financing
Adequate protection amounts paid/accrued
Unrealized mark-to-market net (gains) losses on interest
rate swaps
Amortization of debt issuance costs, discounts and
premiums
Debt extinguishment loss
Capitalized interest
Other

Total interest expense and related charges

$

$

537
—
—

5

—
27
(12)
15
572

$

$

213
—
—

(29)

4
—
(7)
12
193

Successor

Period from
October 3, 2016
through
December 31, 2016
51
$
—
—

Predecessor

Period from
January 1, 2016
through
October 2, 2016
—
$
76
977

11

(1)
—
(3)
2
60

$

—

4
—
(9)
1
1,049

$

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, considering the interest rate swaps

discussed in Note 14, was 4.24% and 4.38% at December 31, 2018 and 2017, respectively.

Predecessor

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

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

Contractual interest on debt classified as LSTC
Adequate protection amounts paid/accrued
Contractual interest on debt classified as LSTC not paid/accrued

125

Predecessor

Period from
January 1, 2016
through 
October 2, 2016
1,570
$
930
640

$

12.  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.

Net loss attributable to common stock — basic (a)

Weighted average shares of common stock outstanding — basic
Net loss per weighted average share of common stock outstanding —
basic
Weighted average shares of common stock outstanding — diluted
Net loss per weighted average share of common stock outstanding —
diluted

$

$

$

Successor

Year Ended
December 31,
2018

Year Ended
December 31,
2017

(54) $

(254) $

504,954,371

427,761,460

Period from 
October 3, 2016
through
December 31, 2016
(163)
427,560,620

(0.11) $

(0.59) $

504,954,371

427,761,460

(0.38)
427,560,620

(0.11) $

(0.59) $

(0.38)

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

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

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

13.  ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

TXU  Energy  Receivables  Company  LLC  (RecCo),  an  indirect  subsidiary  of Vistra  Energy,  has  an  accounts  receivable
financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). 
The Receivables Facility is currently scheduled to terminate in August 2019, unless termination occurs earlier in accordance with 
the terms of the Receivables Facility.  The Receivables Facility provides RecCo with the ability to borrow up to $350 million.

Under the Receivables Facility, TXU Energy may sell or contribute, on an ongoing basis and without recourse, its accounts 
receivable to its special purpose subsidiary, RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU
Energy.  RecCo, in turn, is subject to certain conditions, and may, from time to time, sell an undivided interest in all the receivables
to the Purchasers, and its assets and credit are not available to satisfy the debts and obligations of any person, including affiliates
of RecCo.  Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the consolidated balance sheets.  
Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our statements of 
consolidated cash flows.  Receivables transferred to the Purchasers remain on Vistra Energy's balance sheet and Vistra Energy
reflects a liability equal to the amount advanced by the Purchasers.  The Company records interest expense on amounts advanced.  
TXU Energy continues to service, administer and collect the trade receivables on behalf of RecCo and the Purchasers, as applicable.

a

ff

As of December 31, 2018, the receivables facility totaled $339 million and is supported by $477 million of RecCo gross

receivables.

126

14.  LONG-TERM DEBT

Successor

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

Vistra Operations Credit Facilities
Vistra Operations 5.500% Senior Notes, due September 1, 2026
Vistra Energy Senior Notes:

7.375% Senior Notes, due November 1, 2022
5.875% Senior Notes, due June 1, 2023
7.625% Senior Notes, due November 1, 2024
8.034% Senior Notes, due February 2, 2024
8.000% Senior Notes, due January 15, 2025
8.125% Senior Notes, due January 30, 2026

Total Vistra Energy Senior Notes

Other:

7.000% Amortizing Notes, due July 1, 2019
Forward Capacity Agreements
Equipment Financing Agreements
Mandatorily redeemable subsidiary preferred stock (a)
8.82% Building Financing due semiannually through February 11, 2022 (b)

Total other long-term debt

Unamortized debt premiums, discounts and issuance costs (c)
Total long-term debt including amounts due currently
Less amounts due currently
Total long-term debt less amounts due currently

December 31,

2018

2017

$

$

5,813
1,000

4,311
—

1,707
500
1,147
25
81
166
3,626

24
236
120
70
21
471
155
11,065
(191)
10,874

$

$

—
—
—
—
—
—
—

—
—
—
70
27
97
15
4,423
(44)
4,379

____________
(a)  Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. 

(see Note 5).  This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance.
(b)  Obligation related to a corporate office space capital lease transferred to Vistra Energy pursuant to the Plan of Reorganization.  
This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our 
consolidated balance sheets.
Includes impact of recording debt assumed in the Merger at fair value.

(c) 

Vistra Operations Credit Facilities

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

127

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

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

Vistra Operations Credit Facilities

Revolving Credit Facility (a)
Term Loan B-1 Facility
Term Loan B-2 Facility
Term Loan B-3 Facility

Total Vistra Operations Credit Facilities

Maturity Date
June 14, 2023
August 4, 2023
December 14, 2023
December 31, 2025

$

$

December 31, 2018

Facility
Limit

Cash
Borrowings

Available 
Capacity

2,500
2,793
980
2,040
8,313

$

$

— $

2,793
980
2,040
5,813

$

1,135
—
—
—
1,135

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

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

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

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

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

128

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,tt
and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued 
revolving  letters  of  credit  (in  excess  of  $300  million)  exceed  30%  of  the  revolving  commitments),  the  agreement  includes  a
covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to
an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00.  As of December 31, 2018, we were
in compliance with this financial covenant.  Upon the existence of an event of default, the Vistra Operations Credit Facilities
provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically
or at the election of specified lenders.

a

Interest Rate Swaps — Effective January 2017, we entered into $3.0 billion notional amount of interest rate swaps to hedge
a portion of our exposure to our variable rate debt.  The interest rate swaps expire in July 2023.  In May and June 2018, we entered 
into $3.0 billion notional amount of interest rate swaps that become effective in July 2023 and expire in July 2026.

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

The interest rate swaps effectively fix the interest rates between 4.13% and 4.38% on $4.717 billion of our variable rate debt.  

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

Alternative Letter of Credit Facility

In December 2018, we entered into an alternative letter of credit facility with a facility limit of approximately $193 million

at February 25, 2019.  The facility became effective in January 2019.

Vistra Energy (legacy Dynegy) Credit Agreement

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

f

Vistra Operations Senior Notes

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

129

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

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

Vistra Energy Senior Notes

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

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

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

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

• 
• 
• 
• 

$26 million of 7.625% senior notes due 2024;
$163 million of 8.034% senior notes due 2024;
$669 million of 8.000% senior notes due 2025, and
$684 million of 8.125% senior notes due 2026.

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

d

130

r

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

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

uu

Amortizing Notes

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

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

Forward Capacity Agreements

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

Equipment Financing Agreements

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

a

131

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

2019
2020
2021
2022
2023
Thereafter
Unamortized premiums, discounts and debt issuance costs
Total long-term debt, including amounts due currently

Predecessor

December 31, 2018
191
$
205
129
1,782
4,150
4,453
155
11,065

$

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, yy
$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.

132

15.  COMMITMENTS AND CONTINGENCIES

Contractual Commitments

At December 31, 2018, we had contractual commitments under long-term service and maintenance contracts, energy-related 

contracts, leases and other agreements as follows.

Long-Term Service
and Maintenance
Contracts

Coal purchase and 
transportation 
agreements

Pipeline transportation
and storage
reservation fees

Nuclear
Fuel Contracts

Other 
Contracts

2019
2020
2021
2022
2023
Thereafter
Total

$

$

175
181
135
183
133
2,619
3,426

$

$

765
227
118
103
64
186
1,463

$

$

101
95
72
48
35
145
496

$

$

69
71
58
38
46
155
437

$

$

101
74
20
13
9
68
285

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

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

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

2019
2020
2021
2022
2023
Thereafter

Total future minimum lease payments

Operating Leases (a)

35
29
25
20
19
168
296

$

$

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

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

Guarantees

We have entered into contracts, including the assumed Dynegy senior notes described above, that contain guarantees to 
unaffiliated parties that could require performance or payment under certain conditions.  As of December 31, 2018, there are no
material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material 
payments under these guarantees.

133

Letters of Credit

At December 31, 2018, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $1.365 

billion as follows:

• 

• 
• 
• 

$1.185 billion to support commodity risk management collateral requirements in the normal course of business, including 
over-the-counter and exchange-traded transactions and collateral postings with ISOs or RTOs;
$53 million to support executory contracts and insurance agreements;
$55 million to support our REP financial requirements with the PUCT, and
$72 million for other credit support requirements.

Surety Bonds

At December 31, 2018, we had outstanding surety bonds totaling $31 million to support performance under various contracts

and legal obligations in the normal course of business.

Litigation

aa

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

n

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

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

134

Greenhouse Gas Emissions

In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed 
and existing electricity generation units, referred to as the Clean Power Plan, including rules for existing facilities that would 
establish state-specific emissions rate goals to reduce nationwide CO2 emissions.  Various parties (including Luminant) filed 
petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) and subsequently, in
January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the U.S. Supreme Court 
(Supreme Court) asking that the Supreme Court stay the rule while the D.C. Circuit Court reviews the legality of the rule for 
existing plants.  In February 2016, the Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before
the D.C. Circuit Court and until the Supreme Court disposes of any subsequent petition for review.  Oral argument on the merits
of the legal challenges to the rule was heard in September 2016 before the entire D.C. Circuit Court, but the D.C. Circuit Court rr
has not issued a decision and the case remains in abeyance due to the EPA's decision to review the Clean Power Plan.

In October 2017, the EPA issued a proposed rule that would repeal the Clean Power Plan, with the proposed repeal focusing 
on  what  the  EPA  believes  to  be  the  unlawful  nature  of  the  Clean  Power  Plan  and  asking  for  public  comment  on  the  EPA's 
interpretations of its authority under the Clean Air Act.  In December 2017, the EPA published an advance notice of proposed 
rulemaking (ANPR) soliciting information from the public as the EPA considers proposing a future rule.  Vistra Energy submitted
comments on the ANPR in February 2018.  Vistra Energy submitted comments on the proposed repeal in April 2018.  In August 
2018, the EPA published a proposed replacement rule called the Affordable Clean Energy rule.  We submitted comments on the 
proposed Affordable Clean Energy rule in October 2018.  In December 2018, the EPA issued proposed revisions to the emission
standards for new, modified and reconstructed units with comments due in March 2019.  While we cannot predict the outcome of 
these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately 
implemented or upheld as they were issued, they could have a material impact on our results of operations, liquidity or financial
condition.

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

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

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

h

135

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

Affirmative Defenses During Malfunctions

In February 2013, the EPA proposed a rule requiring certain states to remove SIP exemptions for excess emissions during
malfunctions or replace them with an affirmative defense.  In May 2015, the EPA finalized its 2013 proposal to extend the EPA's
proposed findings of inadequacy to states that have affirmative defense provisions, including Texas.  The final rule impacted 36
states, including Texas, Illinois and Ohio, in which we operate.  The EPA's final rule would require covered states to remove or 
replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during startup, shutdown and 
maintenance events.  Several states (including the State of Texas and the State of Ohio) and various industry parties (including 
Luminant) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court. 
Before the oral argument was held, in April 2017, the D.C. Circuit Court granted the EPA's motion to continue oral argument and
ordered that the case be held in abeyance with the EPA to provide status reports to the D.C. Circuit Court on the EPA's review of 
the action at 90-day intervals.  In October 2018, the EPA partially granted Texas' petition for reconsideration of the Texas SIP call. 
We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation 
of the rule as finalized could have a material impact on our results of operations, liquidity or financial condition.

SO2 Designations for Texas

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

Effluent Limitation Guidelines (ELGs)

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

136

The EPA issued a final rule in September 2017 postponing the earliest compliance dates in the ELG rule for bottom ash

transport water and flue-gas desulfurization wastewater by two years, from November 1, 2018 to November 1, 2020.

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

New Source Review and CAA Matters

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

In August 2013, the U.S. Department of Justice (DOJ), acting as the attorneys for the EPA, filed a civil enforcement lawsuit 
against Luminant in federal district court in Dallas, alleging violations of the CAA, including its NSR standards, at our Big Brown
and  Martin  Lake  generation  facilities.   The  lawsuit  requests  (i)  the  maximum  civil  penalties  available  under  the  CAA  to  the 
government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and 
(ii) injunctive relief, including an order to apply for pre-construction permits which may require the installation of best available 
control technology at the affected units.  In August 2015, the district court granted Luminant's motion to dismiss seven of the nine 
claims asserted by the EPA in the lawsuit.

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

h

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

t

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

tt

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

137

Coal Combustion Residuals/Groundwater

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

n

t

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

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

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

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

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

aa

138

MISO 2015-2016 Planning Resource Auction

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

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

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

Other Matters

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions 
of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or 
financial condition.

Labor Contracts

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

Nuclear Insurance

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

139

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

n

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

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

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

16.  EQUITY

Successor Shareholders' Equity

Equity Issuances and Repurchases — Changes in the number of shares of common stock outstanding for the years ended 

December 31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 are reflected in the table below.

Shares outstanding at beginning of period

Shares issued (a)

Shares retired

Shares repurchased (b)

Shares outstanding at end of period

Year Ended
December 31,
2018
428,398,802

97,639,105
(6,815)
(32,815,783)
493,215,309

Successor

Year Ended
December 31,
2017
427,580,232

Period from
October 3, 2016
through
December 31, 2016
—

818,570

427,580,232

—

—

—

—

428,398,802

427,580,232

____________
(a) 

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

(b)  Treasury  shares  totaled  32,815,783  shares  at  December 31,  2018,  all  of  which  were  acquired  during  the  year  ended 

December 31, 2018 in connection with the share repurchase program described below.

140

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

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

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

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

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

Under applicable Delaware General Corporate Law, we are prohibited from paying any distribution to the extent that such
distribution exceeds the value of our "surplus," which is defined as the excess of our net assets above our capital (the aggregate
par value of all outstanding shares of our stock).

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

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

141

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

Predecessor Membership Interests

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

17.  FAIR VALUE MEASUREMENTS

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the
market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items 
that are measured on a recurring basis.  We use a mid-market valuation convention (the mid-point price between bid and ask prices) 
as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize 
the use of observable inputs and minimize the use of unobservable inputs.  Our valuation policies and procedures were developed, 
maintained and validated by a centralized risk management group that reports to the Vistra Energy Chief Financial Officer.

Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance
risk.  These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the 
credit risks associated with our credit standing and the credit standing of our counterparties (see Note 18 for additional information
regarding credit risk associated with our derivatives).  We utilize credit ratings and default rate factors in calculating these fair 
value measurement adjustments.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:

•  Level  1  valuations  use  quoted  prices  in  active  markets  for  identical  assets  or  liabilities  that  are  accessible  at  the
measurement date.  Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) 
futures and options transacted through clearing brokers for which prices are actively quoted.  We report the fair value 
of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin 
amounts  related  to  changes  in  fair  value  on  certain  CME  transactions  that,  beginning  in  January  2017,  are  legally 
characterized as settlement of derivative contracts rather than collateral.

•  Level  2  valuations  utilize  over-the-counter  broker  quotes,  quoted  prices  for  similar  assets  or  liabilities  that  are 
corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield 
curves observable at commonly quoted intervals.  We attempt to obtain multiple quotes from brokers that are active in 
the markets in which we participate and require at least one quote from two brokers to determine a pricing input as 
observable.  The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading
market, each individual broker's publication policy, recent trading volume trends and various other factors.

•  Level 3 valuations use unobservable inputs for the asset or liability.  Unobservable inputs are used to the extent observable
inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or 
liability at the measurement date.  We use the most meaningful information available from the market combined with 
internally developed valuation methodologies to develop our best estimate of fair value.  Significant unobservable inputs 
used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and 
locations and credit-related nonperformance risk assumptions.  These inputs and valuation models are developed and 
maintained by employees trained and experienced in market operations and fair value measurements and validated by 
the Company's risk management group.

With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or 
liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair
value measurement.

142

Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet 

dates shown below:

December 31, 2018

Level 1

Level 2

Level 3 (a)

Reclassification (b)

Total

Assets:

Commodity contracts
Interest rate swaps
Nuclear decommissioning trust –
equity securities (c)
Nuclear decommissioning trust –
debt securities (c)

Sub-total

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

Liabilities:

Commodity contracts
Interest rate swaps
Total liabilities

Assets:

Commodity contracts
Interest rate swaps
Nuclear decommissioning trust –
equity securities (c)
Nuclear decommissioning trust –
debt securities (c)

Sub-total

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

Liabilities:

Commodity contracts
Interest rate swaps
Total liabilities

$

$

$

$

$

$

$

$

456
—

449

—
905

$

$

152
77

—

443
672

$

$

153
—

—

—
153

$

$

557
—
557

$

$

766
34
800

$

$

288
—
288

$

$

1
—

—

—
1

1
—
1

$

$

$

$

762
77

449

443
1,731

278
2,009

1,612
34
1,646

December 31, 2017

Level 1

Level 2

Level 3 (a)

Reclassification (b)

Total

47
—

468

—
515

$

$

$

98
18

—

430
546

$

75
—

—

—
75

$

$

45
—
45

$

$

143
—
143

$

$

128
—
128

$

$

2
8

—

—
10

2
8
10

$

$

$

$

222
26

468

430
1,146

290
1,436

318
8
326

____________
(a)  See table below for description of Level 3 assets and liabilities.
(b)  Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice 

versa, as presented in our consolidated balance sheets.

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

See Note 23.

(d)  The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts 
presented in our consolidated balance sheets.  Certain investments measured at fair value using the net asset value per share 
(or its equivalent) have not been classified in the fair value hierarchy.

u

143

Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium, coal and emissions agreements and 
include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated 
as normal purchases or sales.  Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate
interest to fixed rates.  See Note 18 for further discussion regarding derivative instruments.

Nuclear  decommissioning  trust  assets  represent  securities  held  for  the  purpose  of  funding  the  future  retirement  and 
decommissioning of our nuclear generation facility.  These investments include equity, debt and other fixed-income securities 
consistent with investment rules established by the NRC and the PUCT.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant 

unobservable inputs used in the valuations at December 31, 2018 and 2017:

December 31, 2018

Fair Value

Contract Type (a)
Electricity purchases
and sales

Assets

Liabilities

Total

$

22

$

(48) $

(26)

Electricity and
weather options

31

(192)

(161)

Financial transmission
rights

Other (h)

85

15

(20)

(28)

65

(13)

Total

$

153

$

(288) $

(135)

Valuation
Technique
Valuation
Model

Option
Pricing
Model

Significant Unobservable Input

Hourly price curve shape (c)

Illiquid delivery periods for
ERCOT hub power prices
and heat rates (d)

Range (b)
$0 to $110/
MWh

$20 to $120/
MWh

Gas to power correlation (e)
Power volatility (e)

15% to 95%
5% to 435%

Market
Approach (f)

Illiquid price differences
between settlement points
(g)

$(10) to $50/
MWh

December 31, 2017

Fair Value

Contract Type (a)
Electricity purchases
and sales

Assets

Liabilities

Total

$

12

$

(33) $

(21)

Electricity and
weather options

—

(91)

(91)

Financial transmission
rights

Other (h)

Total

$

45

18

75

(4)

—

41

18

$

(128) $

(53)

Valuation
Technique
Valuation
Model

Option
Pricing
Model

Significant Unobservable Input

Hourly price curve shape (c)

Illiquid delivery periods for
ERCOT hub power prices
and heat rates (d)

Range (b)
$0 to $40/
MWh

$20 to $70/
MWh

Gas to power correlation (e)
Power volatility (e)

30% to 100%
5% to 180%

Market
Approach (f)

Illiquid price differences
between settlement points
(g)

$0 to $15/
MWh

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

(b)  The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.
(c)  Primarily based on the historical range of forward average hourly ERCOT North Hub prices.
(d)  Primarily based on historical forward ERCOT power price and heat rate variability.
(e)  Based on historical forward correlation and volatility within ERCOT.

144

(f)  While we use the market approach, there is insufficient market data to consider the valuation liquid.
(g)  Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h)  Other includes contracts for natural gas, coal options and emissions.

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

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

Net asset (liability) balance at beginning of period (a)

$

Total unrealized valuation gains (losses)
Purchases, issuances and settlements (b):

Year Ended December 31,

2018

2017

(53) $
(363)

Successor

Period from
October 3, 2016
through
December 31, 2016
81
$
31

Predecessor

Period from
January 1, 2016
through
October 2, 2016
37
$
122

Purchases
Issuances
Settlements

Transfers into Level 3 (c)
Transfers out of Level 3 (c)
Net liabilities assumed in connections with the Merger
Earn-out provision (d)
Net liabilities assumed in the Lamar and Forney
Acquisition (Note 3) (e)

Net change (f)

Net asset (liability) balance at end of period
Unrealized valuation gains (losses) relating to
instruments held at end of period

$

$

83
(136)

69
(22)
(106)
4
71
—
(16)

146
(41)
76
4
133
(37)
—

—
(82)
(135) $

—
(136)
(53) $

(174) $

(98) $

15
(7)
(30)
3
(10)
—
—

—
2
83

28

$

$

37
(20)
(51)
1
1
—
—

(30)
60
97

98

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

(b)  Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income.  Purchases and 

issuances reflect option premiums paid or received.

(c)  Includes transfers due to changes in the observability of significant inputs.  All Level 3 transfers during the periods presented 
are in and out of Level 2.  For the years ended December 31, 2018 and 2017, transfers out of Level 3 primarily consists of 
electricity derivatives where forward pricing inputs have become observable.

(d)  Represents initial fair value of the earn-out provision agreed to as part of the Odessa Acquisition.  See Note 3.
(e)  Includes fair value of Level 3 assets and liabilities as of the purchase date and any related rolloff between the purchase date 

and the period ended October 2, 2016.

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

145

18.  COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price

and interest rate risk.  See Note 17 for a discussion of the fair value of derivatives.

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

Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting 
floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows.  Unrealized gains and losses 
arising from changes in the fair value of the swaps are reported in our statements of consolidated income (loss) in interest expense 
and related charges.

x

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent 
with accounting standards related to derivative instruments and hedging activities.  The following tables provide detail of derivative 
contractual assets and liabilities as reported in our consolidated balance sheets at December 31, 2018 and 2017.  Derivative asset 
and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.

Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities

Net assets (liabilities)

Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities

Net assets (liabilities)

December 31, 2018

Derivative Assets

Derivative Liabilities

Commodity
Contracts

Interest Rate
Swaps

Commodity
Contracts

Interest Rate
Swaps

Total

$

$

$

$

707
54
—
—
761

$

$

22
55
—
—
77

$

$

$

1
—
(1,374)
(238)
(1,611) $

December 31, 2017

— $
—
(2)
(32)
(34) $

730
109
(1,376)
(270)
(807)

Derivative Assets

Derivative Liabilities

Commodity
Contracts

Interest Rate
Swaps

Commodity
Contracts

Interest Rate
Swaps

Total

190
30
—
—
220

$

$

— $
22
(4)
—
18

$

— $

2
(216)
(102)
(316) $

— $

4
(4)
—
— $

190
58
(224)
(102)
(78)

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

146

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.

Derivative (statements of consolidated income (loss) presentation)

2018

2017

Successor

Year Ended December 31,

Commodity contracts (Operating revenues)
Commodity contracts (Fuel, purchased power costs and
delivery fees)
Commodity contracts (Net gain from commodity hedging
and trading activities)
Interest rate swaps (Interest expense and related charges)

Net gain (loss)

$

$

(855) $

18

—
(11)
(848) $

Period from
October 3, 2016
through
December 31, 2016
(92)
$

Predecessor

Period from
January 1, 2016
through
October 2, 2016
—
$

21

—
(11)
(82)

$

—

194
—
194

$

56

6

—
2
64

In conjunction with fresh start reporting, the balances in accumulated other comprehensive income were eliminated from
our consolidated balance sheet on the Effective Date.  The pretax effect (all losses) on net income and other comprehensive income 
(OCI) of derivative instruments previously accounted for as cash flow hedges by the Predecessor was immaterial for the Predecessor 
period from January 1, 2016 through October 2, 2016.  There were no amounts recognized in OCI for the years ended December 
31, 2018 and 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1,
2016 through October 2, 2016.

Balance Sheet Presentation of Derivatives

We elect to report derivative assets and liabilities in our consolidated balance sheets on a gross basis without taking into
consideration netting arrangements we have with counterparties to those derivatives.  We maintain standardized master netting 
agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit 
exposure between us and the counterparty.  These agreements contain specific language related to margin requirements, monthly
settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.

dd

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

147

The  following  tables  reconcile  our  derivative  assets  and  liabilities  on  a  contract  basis  to  net  amounts  after  taking  into 

consideration netting arrangements with counterparties and financial collateral:

December 31, 2018

December 31, 2017

Derivative 
Assets
and 
Liabilities

Offsetting
Instruments
(a)

Cash
Collateral
(Received)
Pledged (b)

Net
Amounts

Derivative 
Assets
and 
Liabilities

Offsetting
Instruments
(a)

Cash
Collateral
(Received)
Pledged (b)

Net
Amounts

Derivative assets:

$

Commodity contracts
Interest rate swaps
Total derivative
assets

761
77

838

$

(593) $
(26)

(1) $
—

(619)

(1)

Derivative liabilities:

Commodity contracts
Interest rate swaps
Total derivative
liabilities

(1,611)
(34)

(1,645)

593
26

619

109
—

109

167
51

218

(909)
(8)

(917)

$

220
18

238

(316)
—

(316)

$

(113) $
—

(1) $
—

(113)

(1)

113
—

113

1
—

1

106
18

124

(202)
—

(202)

Net amounts

$

(807) $

— $

108

$

(699)

$

(78) $

— $

— $

(78)

____________
(a)  Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b)  Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin

requirements.

Derivative Volumes

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

Derivative type
Natural gas (a)
Electricity
Financial Transmission Rights (b)
Coal
Fuel oil
Uranium
Emissions
Interest rate swaps – floating/fixed (c)

December 31, 2018

December 31, 2017

Notional Volume
7,011
317,572
172,611
45
60
50
10
7,717

$

Unit of Measure
1,259 Million MMBtu

114,129 GWh
110,913 GWh

2 Million U.S. tons
5 Million gallons
325 Thousand pounds

— Million tons

3,000 Million U.S. dollars

$

____________
(a)  Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas

transactions.

(b)  Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement 

points within ISOs or RTOs.

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

148

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:

Fair value of derivative contract liabilities (a)
Offsetting fair value under netting arrangements (b)
Cash collateral and letters of credit
Liquidity exposure

2018

2017

$

$

(856) $
218
190
(448) $

(204)
103
41
(60)

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

tt

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

netting arrangements.

Concentrations of Credit Risk Related to Derivatives

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

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance
because all of this exposure is with counterparties with investment grade credit ratings.  However, this concentration increases the
risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and 
liquidity.   The  transactions  with  these  counterparties  contain  certain  provisions  that  would  require  the  counterparties  to  post
collateral in the event of a material downgrade in their credit rating.

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk.  These policies authorize
specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive
and negative exposures associated with a single counterparty.  Credit enhancements such as parent guarantees, letters of credit, 
surety bonds, liens on assets and margin deposits are also utilized.  Prospective material changes in the payment history or financial 
condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty.  
The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.  An event of 
default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available
liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements
if the counterparties owe amounts to us.

rr

149

19.  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 sharea
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.

d

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

a

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

Pension costs
OPEB costs

Total benefit costs recognized as expense

Successor

Year Ended
December 31,
2018

Year Ended
December 31,
2017

$

$

14
9
23

$

$

6
6
12

Period from 
October 3, 2016 
through 
December 31, 2016
2
$
2
4

$

Predecessor

Period from
January 1, 2016 
through 
October 2, 2016
4
$
—
4

$

Market-Related Value of Assets Held in Postretirement Benefit Trusts

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

150

Detailed Information Regarding Pension Benefits

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

Successor

Year Ended
December 31,
2018

Year Ended
December 31,
2017

Period from
October 3, 2016
through
December 31, 2016

Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate (Vistra Energy Plan)
Discount rate (Dynegy Plan & EEI Plan)
Expected return on plan assets (Vistra Energy Plan)
Expected return on plan assets (Dynegy Plan)
Expected return on plan assets (EEI Plan)
Expected rate of compensation increase (Vistra Energy Plan)
Expected rate of compensation increase (Dynegy Plan & EEI Plan)
Interest crediting rate for cash balance plans (Vistra Energy Plan)
Interest crediting rate for cash balance plans (Dynegy Plan & EEI Plan)
Components of Net Pension Cost:
Service cost
Interest cost
Expected return on assets
Immediate pension cost

Net periodic pension cost

Other Changes in Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income:
Net (gain) loss

Total recognized in net periodic benefit cost and other
comprehensive income

Assumptions Used to Determine Benefit Obligations:
Discount rate (Vistra Plan)
Expected rate of compensation increase (Vistra Plan)
Discount rate (Dynegy Plan)
Expected rate of compensation increase (Dynegy Plan)
Interest crediting rate for cash balance plans (Vistra Energy Plan)
Interest crediting rate for cash balance plans (Dynegy Plan & EEI)

$

$
$

$

$

3.74%
4.05%
4.56%
5.94%
4.74%
3.62%
3.50%
3.50%
4.25%

15
21
(23)
1
14

14

28

$

$
$

$

$

4.37%
3.35%
4.37%
3.35%
3.50%
3.50%

4.31%
—%
4.86%
—%
—%
3.50%
—%
4.00%
—%

$

5
6
(5)
— $
$

6

3

9

$

$

3.74%
3.62%
—%
—%
3.50%
—%

3.79%
—%
4.89%
—%
—%
3.50%
—%
4.00%
—%

2
1
(1)
—
2

(4)

(2)

4.31%
3.50%
—%
—%
4.00%
—%

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

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

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

151

Change in Pension Obligation:
Projected benefit obligation at beginning of period

Acquisitions
Service cost
Interest cost
Settlement
Actuarial (gain) loss
Benefits paid

Projected benefit obligation at end of year
Accumulated benefit obligation at end of year
Change in Plan Assets:
Fair value of assets at beginning of period

Acquisitions
Employer contributions
Settlement
Actual gain (loss) on assets
Benefits paid

Fair value of assets at end of year
Funded Status:
Projected pension benefit obligation
Fair value of assets

Funded status at end of year

Amounts Recognized in the Balance Sheet Consist of:
Other current liabilities
Other noncurrent liabilities
Net liability recognized

Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net gain (loss)

Successor

Year Ended December 31,

2018

2017

$

$
$

$

$

$

$

$

$

$

163
502
15
21
(28)
(34)
(24)
615
611

128
428
12
(28)
(26)
(24)
490

$

$
$

$

$

(615) $
490
(125) $

— $

(125)
(125) $

(13) $

144
—
5
6
—
13
(5)
163
157

117
—
—
—
16
(5)
128

(163)
128
(35)

—
(35)
(35)

1

The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated 

benefit obligation (ABO) in excess of the fair value of plan assets.

Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations

Accumulated benefit obligation

Plan assets

Pension Plan Investment Strategy and Asset Allocations

December 31,

2018

2017

$

$

$

615

611

490

$

$

$

163

157

128

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.

152

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

Asset Category:
Fixed income

Global equity securities
Real estate

Credit strategies

Target Allocation Ranges

Vistra Energy Plan
65% - 75%

16% - 24%
4% - 8%

3% - 7%

Dynegy Plan
45% - 55%

29% - 37%
8% - 12%

6% - 10%

EEI Plan
43% - 53%

30% - 38%
9% - 13%

6% - 10%

Expected Long-Term Rate of Return on Assets Assumption

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

Asset Class:
Fixed income securities

Global equity securities

Real estate

Credit strategies

Weighted average

Expected Long-Term Rate of Return

Vistra Energy Plan
4.0%

7.5%

5.4%

6.8%

4.8%

Dynegy Plan

EEI Plan

3.9%

7.5%

5.4%

6.8%

5.3%

3.9%

7.5%

5.4%

6.8%

5.6%

153

Fair Value Measurement of Pension Plan Assets

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

following:

Asset Category:

Interest-bearing cash

Fixed income securities:

Corporate bonds (a)

U.S. Treasuries

Other (b)

Total assets categorized as Level 1 or 2

Assets measured at net asset value (c):

Commingled trusts

Equity securities:

U.S.

International

Fixed income securities:

Corporate bonds (a)

December 31,

Level 1

2018

Level 2

Total

2017

Level 2

$

— $

(6) $

(6) $

(7)

57

—

—

57

61

25

6

86

118

25

6

143

18

119

73

137

347

490

$

65

29

7

94

2

14

13

5

34

128

Total assets measured at net asset value

Total assets

$

___________
(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.

d

154

Detailed Information Regarding Postretirement Benefits Other Than Pensions

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

Successor

Year Ended
December 31, 
2018

Year Ended 
December 31, 
2017

Period from
October 3, 2016
through
December 31, 2016

Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate (Vistra Energy Plan)
Discount rate (Oncor Plan)
Discount rate (Dynegy Plan)
Expected return on plan assets (EEI Union)
Expected return on plan assets (EEI Salaried)
Components of Net Postretirement Benefit Cost:
Service cost
Interest cost
Expected return on plan assets
Amortization of unrecognized amounts
Plan amendments (a)

Net periodic OPEB cost (income)

Other Changes in Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income:
Net (gain) loss and prior service (credit) cost

Total recognized in net periodic benefit cost and other
comprehensive income

Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate (Vistra Energy Plan)
Discount rate (Split-Participant Plan)
Discount rate (Oncor Plan)
Discount rate (Dynegy Plan)
Expected return on plan assets (EEI Union)
Expected return on plan assets (EEI Salaried)

$

$

$

$

3.67%
—%
4.04%
5.10%
4.47%

2
5
(1)
3
—
9

(6)

3

$

$

$

$

4.35%
4.35%
—%
4.35%
5.36%
4.70%

4.11%
4.18%
—%
—%
—%

2
4
—
—
—
6

26

32

$

$

$

$

3.67%
3.67%
—%
—%
—%
—%

4.00%
3.69%
—%
—%
—%

1
1
—
—
(4)
(2)

(5)

(7)

4.11%
—%
4.18%
—%
—%
—%

___________
(a)  Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life ff

insurance benefits for active employees.

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

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

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

155

Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year

Acquisition
Service cost
Interest cost
Participant contributions
Plan amendments (a)
Actuarial (gain) loss
Benefits paid

Benefit obligation at end of year
Change in Plan Assets:
Fair value of assets at beginning of year

Acquisition
Employer contributions
Participant contributions
Benefits paid
Actual loss on assets

Fair value of assets at end of year
Funded Status:
Benefit obligation
Fair value of assets

Funded status at end of year

Amounts Recognized on the Balance Sheet Consist of:
Other noncurrent assets
Other current liabilities
Other noncurrent liabilities
Net liability recognized

Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss and prior service cost

Year Ended December 31,

2018

2017

115
37
2
5
2
4
(9)
(12)
144

$

$

— $
32
8
2
(12)
(1)
29

$

(144) $
29
(115) $

14
$
(8) $

(121)
(115) $

88
—
2
4
2
11
15
(7)
115

—
—
5
2
(7)
—
—

(115)
—
(115)

—
(6)
(109)
(115)

15

$

20

$

$

$

$

$

$

$
$

$

$

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

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

Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year
Rate to which the cost trend is expected to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate

Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year
Rate to which the cost trend is expected to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate

Successor

December 31, 2018

December 31, 2017

6.70%
4.50%
2026

9.90%
4.50%
2027

7.00%
4.50%
2026

10.66%
4.50%
2026

156

Fair Value Measurement of OPEB Plan Assets

At December 31, 2018, the Vistra Energy OPEB plan assets measured at fair value on a recurring basis totaled $29 million

and consisted of $21 million of U.S equities classified as Level 1 and $8 million of U.S. Treasuries classified as Level 2.

Significant Concentrations of Risk

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

Assumed Discount Rate

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

Contributions

—

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

r

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

—

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:

Pension benefits
OPEB

Qualified Savings Plans

2019

2020

2021

2022

2023

2024-28

$
$

46
10

$
$

45
11

$
$

46
11

$
$

46
11

$
$

46
11

$
$

216
49

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

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

plan was merged into the Thrift Plan.

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

157

20.  STOCK-BASED COMPENSATION

Vistra Energy 2016 Omnibus Incentive Plan

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

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

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

Assumption of Dynegy Stock Compensation Plans

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

Instrument Type

Dynegy Awards Prior to
the Merger Date

Vistra Awards Converted
at the Merger Date

Stock Options
Restricted Stock Units
Performance Units

Total

4,096,027
5,718,148
1,538,133

2,670,610 $
3,056,689
938,721

Fair Value of Awards (a)
10
61
18
89

$

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

Stock-Based Compensation Expense

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

Total stock-based compensation expense
Income tax benefit
Stock based-compensation expense, net of tax

158

Successor

Year Ended December 31,

2018

2017

$

$

73
(15)
58

$

$

Period from
October 3, 2016 
through 
December 31, 2016
3
$
(1)
2

$

19
(7)
12

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.

tt

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

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

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

stock option activity:

Successor

Year Ended December 31, 2018

Total outstanding at beginning of period
Awards converted at Merger Date
Granted
Exercised
Forfeited or expired
Total outstanding at end of period

Weighted
Average 
Stock Options
Exercise Price
(in thousands)
14.44
$
8,136
23.19
$
2,671
19.67
5,268
$
(1,082) $
13.91
(494) $
15.14
17.97
$

14,499

Exercisable at December 31, 2018

4,696

$

18.88

Weighted Average
Remaining Contractual
Term (Years)
9.0

7.3

5.2

Aggregate
Intrinsic Value
(in millions)

$

$

$

32.4

85.1

32.6

At December 31, 2018, $48 million of unrecognized compensation cost related to unvested stock options granted under the 

2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 3 years.

159

Restricted Stock Units

The following table summarizes our restricted stock unit activity:

Successor

Year Ended December 31, 2018

Total outstanding at beginning of period
Awards converted at Merger Date
Granted
Exercised
Forfeited or expired
Total outstanding at end of period

Weighted
Restricted Stock 
Average Grant
Units
Date Fair Value
(in thousands)
16.91
$
2,375
15.52
$
3,057
22.41
$
133
(2,114) $
15.48
(225) $
16.69
16.77
$
3,226

Expected to vest

3,222

$

16.85

Weighted Average
Remaining Contractual
Term (Years)
1.9

1.1

1.0

Aggregate
Intrinsic Value
(in millions)

$

$

$

43.5

73.8

73.7

At December 31, 2018, $40 million of unrecognized compensation cost related to unvested restricted stock units granted 

under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 3 years.

Performance Stock Units

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

21.  RELATED PARTY TRANSACTIONS

Successor

In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares

of common stock and TRA Rights in exchange for their claims.

Registration Rights Agreement

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

In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra Energy 
common stock held by certain significant stockholders pursuant to the Registration Rights Agreement, which was declared effective
by the SEC in May 2017.  The registration statement was amended in March 2018.  Pursuant to the Registration Rights Agreement, 
in June 2018, we filed a post-effective amendment to the Form S-1 registration statement on Form S-3, which was declared effective 
by the SEC in July 2018.  Among other things, under the terms of the Registration Rights Agreement:

• 

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

160

• 

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

All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or 
on behalf of the selling stockholders, will be paid by us.  Legal fee expenses paid or accrued by Vistra Energy on behalf of the 
selling stockholders totaled less than $1 million during each of the years ended December 31, 2018 and 2017.

Tax Receivable Agreement

On the Effective Date, Vistra Energy entered into the TRA with a transfer agent on behalf of certain former first lien creditors

of TCEH.  See Note 10 for discussion of the TRA.

Share Repurchase Transaction

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

t

Predecessor

See Note 5 for a discussion of certain agreements entered into on the Effective Date between EFH Corp. and Vistra Energy 
with respect to the separation of the entities, including a separation agreement, a transition services agreement and a tax matters 
agreement.

tt

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

•

•

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

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

•  Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility 
is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to Vistra Energy 
(and prior to the Effective Date, our Predecessor) for contribution to the trust fund with the intent that the trust fund 
assets, reported in other investments in our consolidated balance sheets, will ultimately be sufficient to fund the future
decommissioning liability, reported in asset retirement obligations in our consolidated balance sheets.  The delivery fee
surcharges remitted to our Predecessor totaled $15 million for the Predecessor period from January 1, 2016 through 
October 2, 2016.  Income and expenses associated with the trust fund and the decommissioning liability incurred by
Vistra Energy (and prior to the Effective Date, our Predecessor) are offset by a net change in a receivable/payable that 
ultimately will be settled through changes in Oncor's delivery fee rates.

161

•  EFH Corp. files consolidated federal income tax and Texas state margin tax returns that included our results prior to the 
Effective Date; however, under a Federal and State Income Tax Allocation Agreement, our federal income tax and Texas
margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., 
were recorded as if our Predecessor filed its own corporate income tax return.  For the Predecessor period from January
1, 2016 through October 2, 2016, our Predecessor made income tax payments to EFH Corp. totaling $22 million.

•

•

•

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

In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other 
lenders.  These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group.  Affiliates 
of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with TCEH 
and/or provided financial advisory services to TCEH, in each case in the normal course of business.

Affiliates of GS Capital Partners were parties to certain commodity and interest rate hedging transactions with our 
Predecessor in the normal course of business.

•  Affiliates of the Sponsor Group have sold or acquired debt or debt securities issued by our Predecessor in open market 

transactions or through loan syndications.

22.  SEGMENT INFORMATION

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

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

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

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

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

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

162

Year Ended
December 31,
2018

Year Ended
December 31,
2017

Period from
October 3, 2016
through
December 31, 2016

$

$

$

$

$

$

$

$

5,597
2,634
1,725
817
720
50
208
(2,607)
9,144

$

$

(318) $
(416)
(413)
(152)
(9)
—
(86)

(1,394) $

690
(70)
100
70
36
(50)
(281)
(4)
491

$

$

(7) $
(12)
(8)
(2)
(1)
(613)
71
(572) $

4,058
1,794
—
—
—
964
—
(1,386)
5,430

$

$

(430) $
(229)
—
—
—
(1)
(40)
$
1
(699) $

461
(118)
—
—
—
(68)
(78)
1
198

$

$

— $
(21)
—

—

—
(252)
80
(193) $

912
212
—
—
—
238
—
(171)
1,191

(153)
(53)
—
—
—
—
(11)
1
(216)

111
(271)
—
—
—
16
(17)
—
(161)

—

1

—

—

—
(66)
5
(60)

Operating revenues (a)

Retail
ERCOT
PJM
NY/NE
MISO
Asset Closure
Corporate and Other (b)
Eliminations

Consolidated operating revenues

Depreciation and amortization

Retail
ERCOT
PJM
NY/NE
MISO
Asset Closure
Corporate and Other (b)
Eliminations

Consolidated depreciation and amortization

Operating income (loss)

Retail
ERCOT
PJM
NY/NE
MISO
Asset Closure
Corporate and Other (b)
Eliminations

Consolidated operating income (loss)

Interest expense and related charges

Retail

ERCOT

PJM

NY/NE

MISO

Corporate and Other (b)

Eliminations

Consolidated interest expense and related charges

163

Successor

Year Ended
December 31,
2018

Year Ended
December 31,
2017

Period from
October 3, 2016
through
December 31, 2016
70

(504) $

Income tax (expense) benefit (all Corporate and Other)

Net income (loss)

Retail
ERCOT
PJM
NY/NE
MISO
Asset Closure
Corporate and Other (b)
Eliminations

Consolidated net income (loss)

Capital expenditures, excluding LTSA

Retail
ERCOT
PJM
NY/NE
MISO
Corporate and Other (b)

Consolidated capital expenditures

$

$

$

$

$

45

$

$

712
(55)
100
79
35
(49)
(876)
(2)
(56) $

1
283
41
10
3
58
396

$

$

$

495
(114)
—
—
—
(63)
(573)
1
(254) $

— $

150
—
—
—
26
176

$

114
(268)
—
—
—
17
(26)
—
(163)

5
84
—
—
—
—
89

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

revenues:

Retail
ERCOT
PJM
NY/NE
MISO
Corporate and Other (b)
Eliminations (1)

Consolidated unrealized net losses from mark-to-market
valuations of commodity positions included in operating
revenues

Successor

Year Ended
December 31,
2018

Year Ended
December 31,
2017

$

(12) $
(483)
(50)
(40)
3
(15)
217

18
(305)
—
—
—
—
154

Period from
October 3, 2016
through
December 31, 2016
(6)
$
(295)
—
—
—
—
113

$

(380) $

(133) $

(188)

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

results.

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

in Corporate net income.

164

Total assets
Retail
ERCOT
PJM
NY/NE
MISO
Asset Closure
Corporate and Other and Eliminations

Consolidated total assets

2018

2017

$

$

7,699
9,347
7,188
2,722
836
254
(2,022)
26,024

$

$

6,156
6,821
—
—
—
248
1,375
14,600

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

23.  SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions

Other income:

Office space sublease rental income (a)
Mineral rights royalty income (b)
Sale of land (b)
Curtailment gain on employee benefit plans (a)
Insurance settlement
Interest income
All other

Total other income

Other deductions:

Write-off of generation equipment (b)
Adjustment to asbestos liability

All other

Total other deductions

Successor

Year Ended December 31,

2018

2017

Period from
October 3, 2016
through
December 31, 2016

Predecessor

Period from
January 1, 2016
through
October 2, 2016

$

$

$

8
—
3
—
16
18
2
47

—

—
5
5

$

$

$

11
3
4
—
—
15
4
37

2

—
3
5

$

$

$

$

$

2
1
—
4
—
1
2
10

—

—
—
— $

—
3
—
—
9
3
4
19

45

11
19
75

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

Restricted Cash

December 31, 2018

December 31, 2017

Current
Assets

Noncurrent
Assets

Current
Assets

Noncurrent
Assets

Amounts related to the Vistra Operations Credit Facilities
(Note 14)
Amounts related to restructuring escrow accounts

Total restricted cash

$

$

165

— $
57
57

$

— $
—
— $

— $
59
59

$

500
—
500

Trade Accounts Receivable

Wholesale and retail trade accounts receivable
Allowance for uncollectible accounts
Trade accounts receivable — net

December 31,

2018

2017

$

$

1,106
(19)
1,087

$

$

596
(14)
582

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

million, respectively.

Allowance for Uncollectible Accounts Receivable

Successor

Year Ended December 31,

2018

2017

Period from
October 3, 2016
through
December 31, 2016

Predecessor

Period from
January 1, 2016
through
October 2, 2016

Allowance for uncollectible accounts receivable at
beginning of period

Increase for bad debt expense
Decrease for account write-offs

Allowance for uncollectible accounts receivable at end of
period

$

$

$

14
56
(51)

$

10
43
(39)

19

$

14

$

— $
10
—

10

$

Inventories by Major Category

Materials and supplies
Fuel stock
Natural gas in storage
Total inventories

Other Investments

Nuclear plant decommissioning trust
Assets related to employee benefit plans (Note 19)
Land
Miscellaneous other

Total other investments

Investment in Unconsolidated Subsidiaries

9
20
(16)

13

149
83
21
253

2018

2017

$

$

$

$

286
115
11
412

2018

1,170
31
49
—
1,250

$

$

$

$

2017

1,188
—
49
3
1,240

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

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

166

Nuclear Decommissioning Trust

Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are
carried at fair value.  Decommissioning costs are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers
as a delivery fee surcharge over the life of the plant and deposited by Vistra Energy (and prior to the Effective Date, a subsidiary 
of TCEH) in the trust fund.  Income and expense associated with the trust fund and the decommissioning liability are offset by a 
corresponding change in a regulatory asset/liability (currently a regulatory asset reported in other noncurrent assets) that will 
ultimately be settled through changes in Oncor's delivery fees rates.  If funds recovered from Oncor's customers held in the trust 
fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to 
collect all additional amounts from its customers, with no obligation from Vistra Energy, provided that Vistra Energy complied 
with PUCT rules and regulations regarding decommissioning trusts.  A summary of investments in the fund follows:

r

December 31, 2018

Debt securities (b)
Equity securities (c)

Total

Debt securities (b)
Equity securities (c)

Total

$

$

$

$

Cost (a)

Unrealized gain
7
$
448
455

$

444
280
724

Unrealized loss
$

Fair market value
443
727
1,170

(8) $
(1)
(9) $

December 31, 2017

Cost (a)

Unrealized gain
14
$
495
509

$

418
265
683

Unrealized loss
$

Fair market value
430
758
1,188

(2) $
(2)
(4) $

$

$

____________
(a)  Includes realized gains and losses on securities sold.
(b)  The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating 
of AA or above as graded by S&P or Aa2 by Moody's Investors Services, Inc.  The debt securities are heavily weighted with 
government and municipal bonds and investment grade corporate bonds.  The debt securities had an average coupon rate of 
3.69% and 3.55% at December 31, 2018 and 2017, respectively, and an average maturity of 8 years and 9 years at December 
31, 2018 and 2017, respectively.

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

for U.S. equity investments and the MSCI Inc. EAFE Index for non-U.S. equity investments.

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

years and $190 million after 10 years.

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

from such sales.

Successor

Predecessor

Period from
October 3, 2016
through
December 31, 2016
1
$
9
(11) $
252
$
(272) $

Period from
January 1, 2016
through
October 2, 2016
3
$
(2)
— $
201
$
25
(215)
(30)
$

Year Ended December 31,

Realized gains
Realized losses
Proceeds from sales of securities
Investments in securities

2018

2017

$
$
$
$

$
2
(9) $
252
$
(274) $

167

Property, Plant and Equipment

Power generation and structures
Land
Office and other equipment

Total

Less accumulated depreciation

Net of accumulated depreciation

Nuclear fuel (net of accumulated amortization of $189 million and $111 million)
Construction work in progress

Property, plant and equipment — net

December 31,

2018

2017

$

$

14,604
642
182
15,428
(1,284)
14,144
191
277
14,612

$

$

3,966
540
120
4,626
(282)
4,344
158
318
4,820

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

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

Asset Retirement and Mining Reclamation Obligations (ARO)

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining,
removal of coal/lignite-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs.  There is no
earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the 
regulatory process as part of delivery fees charged by Oncor.

At December 31, 2018, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled 
$1.276 billion, which exceeds the fair value of the assets contained in the nuclear decommissioning trust.  Since the costs to 
ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a 
corresponding regulatory asset has been recorded to our consolidated balance sheet of $106 million in other noncurrent assets.

168

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

Nuclear Plant
Decommissioning

Mining Land
Reclamation

Coal Ash and
Other

Total

Successor:
Liability at December 31, 2016
Additions:
Accretion
Adjustment for change in estimates (a)
Incremental reclamation costs (b)

Reductions:
Payments

Liability at December 31, 2017
Additions:
Accretion
Adjustment for change in estimates
Obligations assumed in the Merger

Reductions:
Payments

Liability at December 31, 2018
Less amounts due currently

Noncurrent liability at December 31, 2018

$

1,200

33
—
—

—
1,233

43
—
—

375

18
81
—

(36)
438

22
56
2

—
1,276
—
1,276

$

(76)
442
(106)
336

$

151

8
44
62

—
265

28
(89)
475

(24)
655
(50)
605

$

1,726

59
125
62

(36)
1,936

93
(33)
477

(100)
2,373
(156)
2,217

____________
(a)  Amounts primarily relate to the impacts of accelerating the ARO associated with the retirements of the Sandow 4, Sandow

5, Big Brown and Monticello plants (see Note 4).

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

(see Note 4).

Other Noncurrent Liabilities and Deferred Credits

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

Retirement and other employee benefits
Uncertain tax positions, including accrued interest
Other

Total other noncurrent liabilities and deferred credits

December 31,

2018

2017

$

$

270
4
66
340

$

$

166
—
54
220

169

Fair Value of Debt

Long-Term Debt (see Note 14):
Long-term debt under the Vistra Operations
Credit Facilities
Vistra Operations Senior Notes
Vistra Energy Senior Notes
7.000% Amortizing Notes
Forward Capacity Agreements
Equipment Financing Agreements
Mandatorily redeemable subsidiary preferred
stock
Building Financing

Fair Value
Hierarchy

Carrying
Amount

Fair 
Value

Carrying
Amount

Fair 
Value

$

Level 2
Level 2
Level 2
Level 2
Level 3
Level 3

Level 2
Level 2

$

5,820
987
3,819
23
221
102

70
23

$

5,599
963
3,765
24
221
102

70
21

$

4,323
—
—
—
—
—

70
30

4,334
—
—
—
—
—

70
27

We determine fair value in accordance with accounting standards as discussed in Note 17.  We obtain security pricing from 
an independent party who uses broker quotes and third-party pricing services to determine fair values.  Where relevant, these
prices are validated through subscription services, such as Bloomberg.

Supplemental Cash Flow Information

The following table reconciles cash, cash equivalents and restricted cash reported in our statements of consolidated cash 

flows to the amounts reported in our balance sheets at December 31, 2018 and 2017:

Cash and cash equivalents
Restricted cash included in current assets
Restricted cash included in noncurrent assets

Total cash, cash equivalents and restricted cash

2018

2017

636
57
—
693

$

$

1,487
59
500
2,046

$

$

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

Cash payments related to:

Interest paid (a)
Capitalized interest

Interest paid (net of capitalized interest) (a)

Income taxes
Reorganization items (b)

Noncash investing and financing activities:

Construction expenditures (c)
Vistra Energy common stock issued in the Merger (Notes
2 and 16)

Successor

Year Ended December 31,

2018

2017

Period from
October 3, 2016
through
December 31, 2016

Predecessor

Period from
January 1, 2016
through
October 2, 2016

$

$
$
$

$

$

$

651
(12)
$
639
67
$
— $

79

2,245

$

$

$

245
(7)
$
238
63
$
— $

12

$

— $

$

19
(3)
$
16
(2)
$
— $

1

$

— $

1,064
(9)
1,055
22
104

53

—

____________
(a)  Predecessor period includes amounts paid for adequate protection.
(b)  Represents cash payments made by our Predecessor for legal and other consulting services, including amounts paid on behalf 

of third parties pursuant to contractual obligations approved by the Bankruptcy Court.

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

170

Quarterly Information (Unaudited)

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

2018(a):
Operating revenues
Operating income (loss)
Net income (loss)
Net income (loss) attributable to Vistra Energy
Net income (loss) per weighted average share of common
stock outstanding — basic
Net income (loss) per weighted average share of common
stock outstanding — diluted

2017:

Operating revenues

Operating income (loss)

Net income (loss)

Net income (loss) attributable to Vistra Energy
Net income (loss) per weighted average share of common
stock outstanding — basic
Net income (loss) per weighted average share of common
stock outstanding — diluted

Successor

Quarter Ended

March 31

June 30

September 30

December 31 (b)

$
$
$
$

$

$

$

$

$

$

$

$

$
765
(394) $
(306) $
(306) $

(0.71) $

(0.71) $

1,357

155

78

78

0.18

0.18

$

$

$

$

$

$

2,574
231
105
108

0.21

0.20

$
$
$
$

$

$

3,243
650
331
330

0.62

0.61

1,296

$

1,833

$
53
(26) $
(26) $

(0.06) $

(0.06) $

452

273

273

0.64

0.64

$
$
$
$

$

$

$

$

$

$

$

$

2,562
4
(186)
(186)

(0.35)

(0.35)

944
(462)
(579)
(579)

(1.35)

(1.35)

____________
(a)  For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.
(b)  For the Successor quarter ended December 31, 2017, operating loss includes noncash charges of $183 million related to the 
generation facilities retirement announcements.  Net loss reflects the retirements mentioned above as well as a $451 million
reduction of deferred tax assets related to the decrease in the corporate tax rate due to the TCJA (see Note 9), partially offset 
by $117 million of impacts of the TRA.

171

24.   SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

u

aa

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

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

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

Condensed Statements of Consolidating Income (Loss)
for the Year Ended December 31, 2018
(Millions of Dollars)

Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses

Operating income (loss)

Other income
Other deductions
Interest expense and related charges
Impacts of Tax Receivable Agreement
Equity in earnings of unconsolidated investment

Income (loss) before income taxes

Income tax expense
Equity in earnings (loss) of subsidiaries, net of tax

Net income (loss)
Net loss attributable to noncontrolling interest
Net income (loss) attributable to Vistra Energy

$

$

Parent
(Issuer)

Guarantor
Subsidiaries
9,043
(4,968)
(1,255)
(1,337)
(660)
823
41
(6)
(309)
—
17
566
(284)
(25)
257
—
257

— $
—
—
—
(266)
(266)
9
—
(257)
(79)
—
(593)
282
257
(54)
—
(54) $

172

Non-
Guarantor
Subsidiaries
174
$
(92)
(42)
(57)
(49)
(66)
—
1
(9)
—
—
(74)
47
—
(27)
2
(25) $

$

Eliminations
$

Consolidated
9,144
(5,036)
(1,297)
(1,394)
(926)
491
47
(5)
(572)
(79)
17
(101)
45
—
(56)
2
(54)

(73) $
24
—
—
49
—
(3)
—
3
—
—
—
—
(232)
(232)
—
(232) $

Condensed Statements of Consolidating Income (Loss)
for the Year Ended December 31, 2017
(Millions of Dollars)

Parent
(Issuer)

Non-
Guarantor
Subsidiaries
$

Eliminations

Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Impairment of long-lived assets
Operating income (loss)

Other income
Other deductions
Interest Income
Interest expense and related charges
Impacts of Tax Receivable Agreement

Income before income taxes

Income tax benefit (expense)
Equity in earnings (losses) of subsidiaries, net of tax

Net income (loss)

$

$

Guarantor
Subsidiaries
5,430
(2,935)
(973)
(699)
(553)
(25)
245
37
(5)
(4)
(193)
—
80
(584)
—
(504) $

— $
—
—
—
(47)
—
(47)
—
—
4
—
213
170
80
(504)
(254) $

Condensed Statements of Consolidating Income (Loss) 
for the Period from October 3, 2016 through December 31, 2016 
(Millions of Dollars)

Non-
Guarantor
Subsidiaries
$

Eliminations

$

Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses

Operating income (loss)

Other income
Interest expense and related charges
Impacts of Tax Receivable Agreement
Income (loss) before income taxes

Income tax expense
Equity in earnings (loss) of subsidiaries, net of tax

Net income (loss)

Parent
(Issuer)

Guarantor
Subsidiaries
1,191
(720)
(208)
(216)
(201)
(154)
10
(60)
—
(204)
274
—
70

— $
—
—
—
(7)
(7)
—
—
(22)
(29)
(204)
70
(163)

173

— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $

— $
—
—
—
—
—
—
—
—
—
—
—
—

Consolidated
5,430
(2,935)
(973)
(699)
(600)
(25)
198
37
(5)
—
(193)
213
250
(504)
—
(254)

— $
—
—
—
—
—
—
—
—
—
—
—
—
—
504
504

$

Consolidated
1,191
(720)
(208)
(216)
(208)
(161)
10
(60)
(22)
(233)
70
—
(163)

— $
—
—
—
—
—
—
—
—
—
—
(70)
(70)

Condensed Statements of Consolidating Comprehensive Income (Loss)
for the Year Ended December 31, 2018
(Millions of Dollars)

Net income (loss)

$

Other comprehensive income (loss), net of tax effects:

Effect related to pension and other retirement
benefit obligations

Adoption of accounting standard

Total other comprehensive income

Comprehensive income (loss)

Comprehensive loss attributable to noncontrolling
interest
Comprehensive income (loss) attributable to Vistra
Energy

Parent
(Issuer)

Guarantor
Subsidiaries
257

(54) $

Non-
Guarantor
Subsidiaries
$

Eliminations

(27) $

(232) $

Consolidated
(56)

—
1
1
(53)

—

(6)
—
(6)
251

—

—
—
—
(27)

2

—
—
—
(232)

—

(6)
1
(5)
(61)

2

$

(53) $

251

$

(25) $

(232) $

(59)

Condensed Statements of Consolidating Comprehensive Income (Loss) 
for the Year Ended December 31, 2017 
(Millions of Dollars)

Parent
(Issuer)

Guarantor
Subsidiaries

Non-
Guarantor
Subsidiaries

Eliminations
504

Consolidated
(254)
$

— $

Net income (loss)

$

(254) $

(504) $

Other comprehensive income (loss), net of tax effects:

Effect related to pension and other retirement
benefit obligations

Total other comprehensive income

Comprehensive income (loss)

(23)
(23)
(277) $

(29)
(29)
(533) $

$

—

—

29

29

— $

533

$

(23)
(23)
(277)

Condensed Statements of Consolidating Comprehensive Income (Loss) 
for the Period from October 3, 2016 through December 31, 2016 
(Millions of Dollars)

Net income (loss)

$

Other comprehensive income (loss), net of tax effects:

Effect related to pension and other retirement
benefit obligations

Total other comprehensive income

Comprehensive income (loss)

Parent
(Issuer)

Guarantor
Subsidiaries
70

(163) $

Non-
Guarantor
Subsidiaries
$

Eliminations

Consolidated
(163)

(70) $

— $

6

6
(157)

6

6

76

—

—

—

(6)
(6)
(76)

6

6
(157)

174

Condensed Statements of Consolidating Cash Flows
for the Year Ended December 31, 2018
(Millions of Dollars)

Cash flows — operating activities:

Cash provided by (used in) operating activities

$

(125) $

1,917

$

(321) $

— $

1,471

Parent
(Issuer)

Guarantor
Subsidiaries

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

Cash flows — financing activities:

Issuances of long-term debt
Repayments/repurchases of debt
Borrowings under accounts receivable securitization
program
Cash dividend paid
Stock repurchase
Debt tender offer and other financing fees
Other, net

Cash provided by (used in) financing activities

Cash flows — investing activities:

Capital expenditures
Nuclear fuel purchases
Cash acquired in the Merger
Development and growth expenditures
Proceeds from sales of nuclear decommissioning trust
fund securities
Investments in nuclear decommissioning trust fund
securities
Dividend received from subsidiaries
Other, net

Cash provided by (used in) investing activities
Net change in cash, cash equivalents and restricted
cash
Cash, cash equivalents and restricted cash — beginning
balance
Cash, cash equivalents and restricted cash — ending
balance

—
(4,543)

—
—
(763)
(179)
12
(5,473)

(24)
—
—
—

—

—
4,668
(1)
4,643

1,000
1,468

—
(4,668)
—
(57)
—
(2,257)

(351)
(118)
445
(31)

252

(274)

7
(70)

(955)

(410)

1,183

863

—
—

339
—
—
—
—
339

(3)
—
—
(3)

—

—

—
(6)

12

—

—
—

4,668
—
—
—
4,668

—
—
—
—

—

—
(4,668)
—
(4,668)

—

—

1,000
(3,075)

339
—
(763)
(236)
12
(2,723)

(378)
(118)
445
(34)

252

(274)
—
6
(101)

(1,353)

2,046

$

228

$

453

$

12

$

— $

693

175

Condensed Statements of Consolidating Cash Flows
for the Year Ended December 31, 2017
(Millions of Dollars)

Cash flows — operating activities:

Cash provided by (used in) operating activities

$

(108) $

1,494

$

— $

— $

1,386

Parent
(Issuer)

Guarantor
Subsidiaries

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

Cash flows — financing activities:
Repayments/repurchases of debt
Cash dividend paid
Debt financing fees
Other, net

Cash provided by (used in) financing activities

Cash flows — investing activities:

Capital expenditures
Nuclear fuel purchases
Development and growth expenditures
Odessa acquisition
Proceeds from sales of nuclear decommissioning trust
fund securities
Investments in nuclear decommissioning trust fund
securities
Dividend received from subsidiaries
Other, net

Cash provided by (used in) investing activities
Net change in cash, cash equivalents and restricted cash

Cash, cash equivalents and restricted cash — beginning
balance
Cash, cash equivalents and restricted cash — ending
balance

—
—
—
—
—

—
—
—
(330)

—

—
1,505
—
1,175
1,067

(191)
(1,505)
(8)
(2)
(1,706)

(114)
(62)
(190)
(25)

252

(272)

14
(397)
(609)

116

1,472

—
—
—
—
—

—
—
—
—

—

—

—
—
—

—

—
1,505
—
—
1,505

—
—
—
—

—

—
(1,505)
—
(1,505)
—

(191)
—
(8)
(2)
(201)

(114)
(62)
(190)
(355)

252

(272)
—
14
(727)
458

—

1,588

$

1,183

$

863

$

— $

— $

2,046

176

Condensed Statements of Consolidating Cash Flows
for the Period from October 3, 2016 through December 31, 2016 
(Millions of Dollars)

Cash flows — operating activities:

Cash provided by (used in) operating activities

$

(36) $

117

$

— $

— $

81

Parent
(Issuer)

Guarantor
Subsidiaries

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

Cash flows — financing activities:

Issuances of long-term debt
Cash dividend paid
Special dividends
Other, net

Cash provided by (used in) financing activities

Cash flows — investing activities:

Capital expenditures
Nuclear fuel purchases
Proceeds from sales of nuclear decommissioning
trust fund securities
Investments in nuclear decommissioning trust fund
securities
Dividend received from subsidiaries
Other, net

Cash provided by (used in) investing activities
Net change in cash, cash equivalents and restricted
cash
Cash, cash equivalents and restricted cash —
beginning balance
Cash, cash equivalents and restricted cash — ending
balance

—
—
(992)
1
(991)

—
—

—

—
997
—
997

(30)

146

1,000
(997)
—
(3)
—

(48)
(41)

25

(30)
—
1
(93)

24

1,448

—
—
—
—
—

—
—

—

—
—
—
—

—

—

—
997
—
—
997

—
—

—

—
(997)
—
(997)

—

—

1,000
—
(992)
(2)
6

(48)
(41)

25

(30)
—
1
(93)

(6)

1,594

$

116

$

1,472

$

— $

— $

1,588

177

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

Parent (Issuer)

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

$

$

$

Current assets:

ASSETS

Cash and cash equivalents
Restricted cash
Advances to affiliates
Trade accounts receivable — net
Accounts receivable — affiliates
Notes due from affiliates
Income taxes receivable
Inventories
Commodity and other derivative contractual assets
Margin deposits related to commodity contracts
Prepaid expense and other current assets

Total current assets

Investments
Investment in unconsolidated subsidiary
Investment in affiliated companies
Property, plant and equipment — net
Goodwill
Identifiable intangible assets — net
Commodity and other derivative contractual assets
Accumulated deferred income taxes
Other noncurrent assets
Total assets

LIABILITIES AND EQUITY

Current liabilities:

Accounts receivable securitization program
Advances from affiliates
Long-term debt due currently
Trade accounts payable
Accounts payable — affiliates
Notes due to affiliates
Commodity and other derivative contractual
liabilities
Margin deposits related to commodity contracts
Accrued taxes
Accrued taxes other than income
Accrued interest
Asset retirement obligations
Other current liabilities

Total current liabilities

453
—
11
729
245
101
1
391
730
361
134
3,156
1,218
131
263
14,017
2,068
2,480
109
599
330
24,371

$

$

— $
—
163
928
—
—

1,376
4
—
181
29
156
267
3,104

$

$

$

12
—
—
464
—
—
—
21
—
—
16
513
32
—
—
580
—
3
—
—
5
1,133

339
22
5
121
9
101

—
—
—
1
4
—
4
606

— $
—
(22)
(110)
(245)
(101)
(1)
—
—
—
—
(479)
—
—
(11,449)
—
—
—
—
(72)
—
(12,000) $

— $
(22)
—
(106)
(245)
(101)

—
—
(1)
—
(4)
—
—
(479)

636
57
—
1,087
—
—
—
412
730
361
152
3,435
1,250
131
—
14,612
2,068
2,493
109
1,336
590
26,024

339
—
191
945
—
—

1,376
4
10
182
77
156
345
3,625

171
57
11
4
—
—
—
—
—
—
2
245
—
—
11,186
15
—
10
—
809
255
12,520

$

$

— $
—
23
2
236
—

—
—
11
—
48
—
74
394

178

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

Parent (Issuer)

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Commodity and other derivative contractual liabilities
Accumulated deferred income taxes
Tax Receivable Agreement obligation
Asset retirement obligations
Identifiable intangible liabilities — net
Other noncurrent liabilities and deferred credits

Total liabilities
Total stockholders' equity
Noncontrolling interest in subsidiary
Total liabilities and equity

—
—
420
—
—
20
4,653
7,867
—
12,520

$

270
—
—
2,203
278
303
13,185
11,186
—
24,371

$

$

—
82
—
14
123
17
870
259
4
1,133

$

—
(72)
—
—
—
—
(551)
(11,449)
—
(12,000) $

270
10
420
2,217
401
340
18,157
7,863
4
26,024

179

Condensed Consolidating Balance Sheet as of December 31, 2017
(Millions of Dollars)

Parent (Issuer)

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries

Eliminations

Consolidated

Current assets:

ASSETS

Cash and cash equivalents
Restricted cash
Trade accounts receivable — net
Inventories
Commodity and other derivative contractual assets
Margin deposits related to commodity contracts
Prepaid expense and other current assets

Total current assets

Restricted cash
Investments
Investment in affiliated companies
Property, plant and equipment — net
Goodwill
Identifiable intangible assets — net
Commodity and other derivative contractual assets
Accumulated deferred income taxes
Other noncurrent assets
Total assets

LIABILITIES AND EQUITY

Current liabilities:

Long-term debt due currently
Trade accounts payable
Commodity and other derivative contractual
liabilities
Margin deposits related to commodity contracts
Accrued taxes
Accrued taxes other than income
Accrued interest
Asset retirement obligations
Other current liabilities

Total current liabilities

Long-term debt, less amounts due currently
Commodity and other derivative contractual liabilities
Tax Receivable Agreement obligation
Asset retirement obligations
Identifiable intangible liabilities — net
Other noncurrent liabilities and deferred credits

Total liabilities
Total equity
Total liabilities and equity

$

$

$

— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $

—
—

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $

— $
—
—
—
—
—
—
—
—
—
(5,632)
—
—
—
—
—
—
(5,632) $

—
—

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(5,632)
(5,632) $

1,487
59
582
253
190
30
72
2,673
500
1,240
—
4,820
1,907
2,530
58
710
162
14,600

44
473

224
4
58
136
16
99
297
1,351
4,379
102
333
1,837
36
220
8,258
6,342
14,600

363
—
578
253
190
30
72
1,486
500
1,240
—
4,820
1,907
2,530
58
705
156
13,402

44
462

224
4
—
136
16
99
211
1,196
4,379
102
—
1,837
36
220
7,770
5,632
13,402

$

$

$

$

$

$

1,124
59
4
—
—
—
—
1,187
—
—
5,632
—
—
—
—
5
6
6,830

—
11

—
—
58
—
—
—
86
155
—
—
333
—
—
—
488
6,342
6,830

180

Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL 

DISCLOSURE

None.

Item 9A.  CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal 
executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and 
procedures in effect at December 31, 2018.  Based on the evaluation performed, our management, including the principal executive 
officer and principal financial officer, concluded that the disclosure controls and procedures were effective.

Other than the changes resulting from the Merger, there have been no change in our internal control over financial reporting
during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our 
internal control over financial reporting.

VISTRA ENERGY CORP.
MANAGEMENT’S ANNUAL REPORT ON 
INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Vistra Energy Corp. is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Vistra Energy
Corp.'s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate 
because of changes in condition or the deterioration of compliance with procedures or policies.

aa

The management of Vistra Energy Corp. performed an evaluation as of December 31, 2018 of the effectiveness of the company's
internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission’s 
(COSO's) Internal Control - Integrated Framework (2013). Based on the review performed, management believes that as of 
December 31, 2018 Vistra Energy Corp.'s internal control over financial reporting was effective.

The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements
of Vistra Energy Corp. has issued an attestation report on Vistra Energy Corp.’s internal control over financial reporting.

/s/ Curtis A. Morgan
Curtis A. Morgan
President and Chief Executive Officer
(Principal Executive Officer)

February 28, 2019

/s/ J. William Holden
J. William Holden
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

181

 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Vistra Energy Corp.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Vistra Energy Corp. and its subsidiaries (the "Company") as of
December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of 
Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, 
effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - 
Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) 
(PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Company and our report 
dated February 28, 2019, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment 
of the effectiveness of internal control over financial reporting, included in the accompanying Annual Report on Internal Control
over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting
based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect 
to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and 
Exchange Commission and the PCAOB.

aa

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the 
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 
performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable 
basis for our opinion.

a

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted 
accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain 
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are 
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable 
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that 
could have a material effect on the financial statements.

a

Because  of  its  inherent  limitations,  internal  control  over  financial  reporting  may  not  prevent  or  detect  misstatements. Also, 
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because 
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Dallas, TX
February 28, 2019

Item 9B.  OTHER INFORMATION

None.

182

Item 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Code of Ethics

PART III

Vistra Energy has adopted a code of ethics entitled "Vistra Energy Code of Conduct" that applies to directors, officers and 
employees, including the chief executive officer and senior financial officers of Vistra Energy.  It may be accessed through the 
"Corporate Governance" section of the Company's website at www.vistraenergy.com.  Vistra Energy also elects to disclose the 
information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the 
Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-
month period.  A copy of the "Vistra Energy Code of Conduct" is available in print to any stockholder who requests it.

Other  information  required  by  this  Item  is  incorporated  by  reference  to  the  similarly  named  section  of Vistra  Energy's

Definitive Proxy Statement for its 2019 Annual Meeting of Stockholders.

Item 11.  EXECUTIVE COMPENSATION

Information required by this Item is incorporated by reference to the similarly named section of Vistra Energy's Definitive 

Proxy Statement for its 2019 Annual Meeting of Stockholders.

Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED

STOCKHOLDER MATTERS

Information required by this Item is incorporated by reference to the sections entitled "Beneficial Ownership of Common

Stock of the Company" in Vistra Energy's Definitive Proxy Statement for its 2019 Annual Meeting of Stockholders.

Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this Item is incorporated by reference to the sections entitled "Business Relationships and Related 
Person Transactions  Policy"  and  "Director  Independence"  in Vistra  Energy's  Definitive  Proxy  Statement  for  its  2019 Annual 
Meeting of Stockholders.

Item 14.  PRINCIPAL ACCOUNTING FEES

Information required by this Item is incorporated by reference to the sections entitled "Principal Accounting Fees" in Vistra

Energy's Definitive Proxy Statement for its 2019 Annual Meeting of Stockholders.

183

Item 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

PART IV

(a) Our financial statements and financial statement schedules are incorporated under Part II, Item 8 of this Annual Report on

Form 10-K.

(b)  EXHIBITS:

Vistra Energy Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2018

Exhibits

Previously Filed With File
Number*

As
Exhibit

(2)

2.1

2.2

(3(i))

3.1

3.2

Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession

333-215288
Form S-1 
(filed December 23, 2016)

001-38086
Form 8-K 
(filed October 31, 2017)

Articles of Incorporation

333-215288
Form S-1 
(filed December 23, 2016)

333-215288
Form S-1 
(filed December 23, 2016)

2.1

2.1

3.1

3.2

— Order  of  the  United  States  Bankruptcy  Court  for  the  District  of 
the  Third  Amended  Joint  Plan  of 

Delaware  Confirming 
Reorganization

— Agreement and Plan of Merger, dated as of October 29, 2017, by and 

between Vistra Energy Corp. and Dynegy, Inc.

Certification of Incorporation of TCEH Corp. (now known as Vistra
Energy Corp.), dated October 3, 2016

— Certificate of Amendment of Certificate of Incorporation of TCEH
Corp. (now known as Vistra Energy Corp.), dated November 2, 2016

(3(ii))

By-laws

3.3

(4)

4.1

4.2

4.3

4.4

4.5

4.6

333-215288
Form S-1 
(filed December 23, 2016)

3.3

— Restated Bylaws of Vistra Energy Corp., dated November 4, 2016

Instruments Defining the Rights of Security Holders, Including Indentures

001-33443
Form 8-K
(filed on October 30, 2014)

001-33443
Form 8-K
(filed on April7, 2015)

001-33443
Form 8-K
(filed on April 7, 2015)

001-33443
Form 8-K
(filed on April 8, 2015)

4.8

— 2022  Notes  Indenture,  dated  October  27,  2014,  among  Dynegy 

Finance II, Inc. and the Trustee

4.11 — First  Supplemental  Indenture  to  the  2022  Notes  Indenture,  dated 

April 1, 2015, between Dynegy and the Trustee

4.12 — Second Supplemental Indenture to the 2022 Notes Indenture, dated 
April 1, 2015, among Dynegy, the Subsidiary Guarantors and the
Trustee

4.17 — Third Supplemental Indenture to the 2022 Notes Indenture, dated 
April 2, 2015, among Dynegy, the Subsidiary Guarantors and the
Trustee

001-33443
Form 10-Q (Quarter ended 
June 30, 2015) 
(filed on August 7, 2015)

001-33443
Form 10-Q (Quarter ended 
September 30, 2015) (filed 
on November 5, 2015)

4.2

4.2

— Fourth Supplemental Indenture to the 2022 Notes Indenture, dated 
May 11, 2015, among Dynegy, the Subsidiary Guarantors and the 
Trustee

— Fifth  Supplemental  Indenture  to  the  2022  Notes  Indenture,  dated 
September 21, 2015, among Dynegy, the Subsidiary Guarantors and 
the Trustee

184

Exhibits

4.7

4.8

4.9

4.10

4.11

4.12

4.13

4.14

4.15

4.16

4.17

4.18

4.19

4.20

4.21

Previously Filed With File
Number*

001-33443
Form 10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

001-33443
Form 10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

001-38086
Form 8-K
(filed on April 9, 2018)

001-38086
Form 8-K
(filed on June 15, 2018)

001-38086
Form 8-K
(filed on February 9, 2019)

001-33443
Form 8-K
(filed on October 30, 2014)

001-33443
Form 8-K
(filed on May 21, 2013)

001-33443
Form 10-K (Year ended 
December 31, 2013) (filed 
on February 27, 2014)

001-33443
Form 8-K
(filed on April 7, 2015)

001-33443
Form 8-K
(filed on April 8, 2015)

001-33443
Form 10-Q (Quarter ended 
June 30, 2015)
(filed on August 7, 2015)

001-33443
Form 10-Q (Quarter ended 
September 30, 2015) (filed 
on November 5, 2015)

001-33443
Form10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

001-33443
Form10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

As
Exhibit
4.24 — Sixth  Supplemental  Indenture  to  the  2022  Notes  Indenture,  dated 
February 2, 2017, among Dynegy, the Subsidiary Guarantors and the
Trustee

4.25 — Seventh Supplemental Indenture to the 2022 Notes Indenture, dated 
February 7, 2017, among Dynegy, the Subsidiary Guarantors and the
Trustee

4.19 — Eighth Supplemental Indenture to the 2022 Notes Indenture, dated 
April 9, 2018, among the Company, the Subsidiary Guarantors and 
the Trustee

4.1

4.4

— Ninth Supplemental Indenture to the 2022 Notes Indenture, dated 
June 14, 2018, among the Guaranteeing Subsidiaries, the Company, 
the Subsidiary Guarantors and the Trustee

— Tenth Supplemental Indenture to the 2022 Notes Indenture, dated 
February 6, 2019, by and among the Company and the Trustee.

4.8

— Form of 7.375% Senior Note due 2022

4.1

— 2023  Notes  Indenture,  dated  May  20,  2013,  among  Dynegy,  the 

Subsidiary Guarantors and the Trustee

4.3

— First Supplemental Indenture to the 2023 Notes Indenture, dated as
of December 5, 2014, among Dynegy, the Subsidiary Guarantors and 
the Trustee

4.20 — Second Supplemental Indenture to the 2023 Notes Indenture, dated 
April 1, 2015, among Dynegy, the Subsidiary Guarantors and the
Trustee

4.28 — Third Supplemental Indenture to the 2023 Notes Indenture, dated 
April 2, 2015, among Dynegy, the Subsidiary Guarantors and the
Trustee

4.4

— Fourth Supplemental Indenture to the 2023 Notes Indenture, dated 

May 11, 2015, among Dynegy, the Subsidiary Guarantors

4.4

4.7

4.8

— Fifth  Supplemental  Indenture  to  the  2023  Notes  Indenture,  dated 
September 21, 2015, among Dynegy, the Subsidiary Guarantors and 
the Trustee

— Sixth  Supplemental  Indenture  to  the  2023  Notes  Indenture,  dated 
February 2, 2017, among Dynegy, the Subsidiary Guarantors and the
Trustee

— Seventh Supplemental Indenture to the 2023 Notes Indenture, dated 
February 7, 2017, among Dynegy, the Subsidiary Guarantors and the
Trustee

001-38086
Form 8-K
(filed on April 9, 2018)

4.29 — Eighth Supplemental Indenture to the 2023 Notes Indenture, dated 
April 9, 2018, among the Company, the Subsidiary Guarantors and 
the Trustee

185

Exhibits

4.22

4.23

4.24

4.25

4.26

4.27

4.28

4.29

4.30

4.31

4.32

4.33

4.34

4.35

4.36

4.37

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on June 15, 2018)

001-33443
Form 8-K
(filed on May 21, 2013)

001-33443
Form 8-K
(filed on October 30, 2014)

001-33443
Form 8-K
(filed on April 7, 2015)

001-33443
Form 8-K
(filed on April 7, 2015)

001-33443
Form 8-K
(filed on April 8, 2015)

001-33443
Form 10-Q (Quarter ended 
June 30, 2015)
(filed on August 7, 2015)

001-33443
Form 10-Q (Quarter ended 
September 30, 2015) (filed 
on November 5, 2015)

001-33443
Form 10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

001-33443
Form 10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

001-38086
Form 8-K
(filed on April 9, 2018)

001-38086
Form 8-K
(filed on June 15, 2018)

001-33443
Form of 8-K
(filed on October 30, 2014)

001-33443 Form 8-K 
(filed on October 11, 2016)

001-33443
Form 10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

001-33443
Form 10-K (Year ended 
December 31, 2016) (filed 
on February 24, 2017)

As
Exhibit
4.2

— Ninth Supplemental Indenture to the 2023 Notes Indenture, dated 
June 14, 2018, among the Guaranteeing Subsidiaries, the Company, 
the Subsidiary Guarantors and the Trustee

4.1

— Form of 5.875% Senior Note due 2023

4.9

— 2024  7.625%  Notes  Indenture,  dated  October  27,  2014,  among

Dynegy Finance II, Inc. and the Trustee

4.14 — First Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated April 1, 2015, between Dynegy and the Trustee

4.15 — Second Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated April 1, 2015, among Dynegy, the Subsidiary Guarantors and 
the Trustee

4.21 — Third Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated April 2, 2015, among Dynegy, the Subsidiary Guarantors and 
the Trustee

4.3

4.3

— Fourth Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated May 11, 2015, among Dynegy, the Subsidiary Guarantors and 
the Trustee

— Fifth Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated  September  21,  2015,  among  Dynegy,  the  Subsidiary
Guarantors and the Trustee

4.32 — Sixth Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated February 2, 2017, among Dynegy, the Subsidiary Guarantors
and the Trustee

4.33 — Seventh  Supplemental  Indenture  to  the  2024  7.625%  Notes
Indenture, dated February 7, 2017, among Dynegy, the Subsidiary
Guarantors and the Trustee

4.39 — Eighth Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated April 9, 2018, among the Company, the Subsidiary Guarantors
and the Trustee

4.3

— Ninth Supplemental Indenture to the 2024 7.625% Notes Indenture,
dated  June  14,  2018,  among  the  Guaranteeing  Subsidiaries,  the 
Company, the Subsidiary Guarantors and the Trustee

4.9

— Form of 7.625% Senior Note due 2024

4.1

— 2025 Notes Indenture, dated October 11, 2016, between Dynegy and 

the Trustee

4.35 — First  Supplemental  Indenture  to  the  2025  Notes  Indenture,  dated 
February 2, 2017, between Dynegy, the Subsidiary Guarantors and 
the Trustee

4.36 — Second Supplemental Indenture to the 2025 Notes Indenture, dated 
February 7, 2017, between Dynegy, the Subsidiary Guarantors and 
the Trustee

186

Exhibits

4.38

4.39

4.40

4.41

4.42

4.43

4.44

4.45

4.46

4.47

4.48

4.49

4.50

4.51

4.52

4.53

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on April 9, 2018)

001-38086
Form 8-K
(filed on June 15, 2018)

001-38086
Form 8-K
(filed on August 23, 2018)

001-33443
Form 8-K 
(filed on October 11, 2016)

001-33443
Form 8-K 
(filed on August 21, 2017)

001-33443
Form 8-K 
(filed on August 21, 2017)

001-38086
Form 8-K
(filed on April 9, 2018)

001-38086
Form 8-K
(filed on June 15, 2018)

001-38086
Form 8-K
(filed on August 23, 2018)

001-33443
Form 8-K
(filed on August 21, 2017)

001-38086
Form 8-K
(filed on August 23, 2018)

001-38086
Form 8-K
(filed on August 23, 2018)

001-38086
Form 8-K
(filed on August 23, 2018)

As
Exhibit
4.48 — Third Supplemental Indenture to the 2025 Notes Indenture, dated 
April 9, 2018, among the Company, the Subsidiary Guarantors and 
the Trustee

4.5

4.6

— Fourth Supplemental Indenture to the 2025 Notes Indenture, dated 
June 14, 2018, among the Guaranteeing Subsidiaries, the Company, 
the Subsidiary Guarantors and the Trustee

— Fifth  Supplemental  Indenture  to  the  2025  Notes  Indenture,  dated 
August 22, 2018, by and among the Company and Wilmington Trust,
National Association, as Trustee

4.1

— Form of 8.000% Senior Note due 2025

4.1

— 2026 Notes Indenture, dated August 21, 2017, among Dynegy, the 

Subsidiary Guarantors and the Trustee

4.2

— Registration  Rights  Agreement,  dated  August  21,  2017,  among

Dynegy, the Subsidiary Guarantors and the Trustee

4.52 — First  Supplemental  Indenture  to  the  2026  Notes  Indenture,  dated 
April 9, 2018, among the Company, the Subsidiary Guarantors and 
the Trustee

4.6

4.4

— Second Supplemental Indenture to the 2026 Notes Indenture, dated 
June 14, 2018, among the Guaranteeing Subsidiaries, the Company, 
the Subsidiary Guarantors and the Trustee

— Third Supplemental Indenture to the 2026 Notes Indenture, dated 
August 22, 2018, by and among the Company and Wilmington Trust,
National Association, as Trustee

4.1

— Form of 8.125% Senior Note due 2026

4.1

— Indenture for 5.500% Senior Note due 2026, dated as of August 22,
2018,  among  Vistra  Operations  Company  LLC,  as  issuer,  the
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee

4.2

— Form  of  Rule  144A  Global  Security  for  5.500%  Senior  Note  due

2026 (included in Exhibit 4.1)

4.3

— Form of Regulation S Global Security for 5.500% Senior Note due

2026 (included in Exhibit 4.1)

001-38086
Form 8-K
(filed on February 6, 2019)

4.1

— Indenture for 5.675% Senior Note due 2027, dated as of February 6,
2019,  among  Vistra  Operations  Company  LLC,  as  issuer,  the
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee

001-38086
Form 8-K
(filed on February 6, 2019)

001-38086
Form 8-K
(filed on February 6, 2019)

4.2

— Form of Rule 144A Global Security for 5.675% Senior Note due2027

(included in Exhibit 4.1)

4.3

— Form of Regulation S Global Security for 5.675% Senior Note due

2027 (included in Exhibit 4.1)

187

Exhibits

4.54

4.55

4.56

4.57

4.58

4.59

4.60

4.61

4.62

4.63

4.64

4.65

4.66

4.67

(10)

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on August 23, 2018)

001-38086
Form 8-K
(filed on August 23, 2018)

As
Exhibit
4.7

4.8

— Purchase and Sale Agreement dated as of August 21, 2018, between 
TXU Energy Retail Company LLC as originator, and TXU Energy
Receivables Company LLC, as purchaser

— Receivable Purchase Agreement dated as of August 21, 2018, among
TXU  Energy  Receivables  Company  LLC,  as  seller, TXU  Energy
Retail Company LLC, as servicer, Vistra Operations Company LLC, 
as performance guarantor, certain purchaser agents and purchasers
named therein and Credit Agricole Corporate and Investment Bank,
as administrator

001-33443
Form 8-K
(filed on June 21, 2016)

001-38086
Registration Statement on 
Form 8-A
(filed on April 9, 2018)

001-33443
Form 8-K
(filed on June 21, 2016)

001-33443
Form 8-K
(filed on June 21, 2016)

001-33443
Form 8-K
(filed on June 21, 2016)

001-33443
Form 8-K
(filed on June 21, 2016)

001-38086
Registration Statement on 
Form 8-A
(filed on April 9, 2018)

001-33443
Form 8-K
(filed on June 21, 2016)

4.3

— Purchase Contract Agreement, dated June 21, 2016, between Dynegy 

and the Trustee

4.5

— First Supplement to the Purchase Contract Agreement, dated April
9, 2018, between the Company, the Purchase Contract Agent and the 
Trustee

4.3

— Form of Unit

4.3

— Form of Purchase Contract

4.1

— Amortizing Notes Indenture, dated June 21, 2016, between Dynegy 

and the Trustee

4.2

— First  Supplemental  Indenture  to  the Amortizing  Notes  Indenture,

dated June 21, 2016, between Dynegy and the Trustee

4.3

— Second Supplemental Indenture to the Amortizing Notes Indenture,

dated April 9, 2018, between the Company and the Trustee

4.2

— Form of Amortizing Note

001-33443
Form of 8-K
(filed on February 7, 2017)

4.1

— Warrant Agreement, dated February 2, 2017, by and among Dynegy,
Computershare  Inc.  and  Computershare Trust  Company,  N.A.,  as 
warrant agent

001-38086
Registration Statement on 
Form 8-A
(filed on April 9, 2018)

001-33443
Form of 8-K
(filed on February 7, 2017)

333-215288
Form S-1 
(filed December 23, 2016)
Material Contracts

4.2

— Supplemental Warrant Agreement, dated as of April 9, 2018 among

the Company and the Warrant Agent

4.1

— Form of Warrant

4.1

— Registration Rights Agreement, by and among TCEH Corp. (now 
known as Vistra Energy Corp.) and the Holders party thereto, dated 
as of October 3, 2016

Management Contracts; Compensatory Plans, Contracts and Arrangements

188

Exhibits

10.1

10.2

10.3

10.4

10.5

10.6

10.7

10.8

10.9

10.10

10.11

10.12

10.13

10.14

Previously Filed With File
Number*

333-215288
Amendment No. 2
to Form S-1 
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

001-33443
Form10-K (Year ended 
December 31, 2017) (filed 
on February 26, 2018)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

**

**

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

001-38086
Form 8-K 
(filed April 27, 2018)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

001-38086
Form 8-K 
(filed May 4, 2018)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

As
Exhibit
10.6 — 2016 Omnibus Incentive Plan

10.7 — Form of Option Award Agreement (Management) for 2016 Omnibus

Incentive Plan

10.8 — Form of Restricted Stock Unit Award Agreement (Management) for 

2016 Omnibus Incentive Plan

10(d) — Form  of  Performance  Stock  Unit  Award  Agreement  for  2016

Omnibus Incentive Plan

10.9 — Vistra Energy Corp. Executive Annual Incentive Plan

—

—

— Amended and Restated 2016 Omnibus Incentive Plan, effective as

of February 26, 2019

— Vistra  Energy  Equity  Deferred  Compensation  Plan  for  Certain

Directors

10.10 — Stockholder's  Agreement,  dated  as  of  October  3,  2016,  by  and 
between  TCEH  Corp.  (now  known  as  Vistra  Energy  Corp.)  and 
Apollo Management Holdings, L.P.

10.11 — Stockholder's  Agreement,  dated  as  of  October  3,  2016,  by  and 
between  TCEH  Corp.  (now  known  as  Vistra  Energy  Corp.)  and 
Brookfield Asset Management Private Institutional Capital Adviser 
(Canada)

10.12 — Stockholder's  Agreement,  dated  as  of  October  3,  2016,  by  and 
between  TCEH  Corp.  (now  known  as  Vistra  Energy  Corp.)  and 
Oaktree Capital Management, L.P. and certain of its affiliated entities

10.1 — Termination of Stockholder’s Agreement, dated as of April 24,2018,

by and among the Company and the Oaktree Stockholder

10.19 — Employment  Agreement  between  Curtis  A.  Morgan  and  Vistra

Energy Corp.

10.1 — Amended and Restated Employment Agreement, dated as of May 

1,2018, between Curtis A. Morgan and Vistra Energy Corp.

10.20 — Employment Agreement between James A. Burke and Vistra Energy

Corp.

189

Exhibits

10.15

10.16

10.17

10.18

10.19

10.20

10.21

10.22

10.23

10.24

10.25

10.26

10.27

Previously Filed With File
Number*

333-215288
Amendment No. 2
to Form S-1 
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

**

**

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

As
Exhibit
10.21 — Employment Agreement between William Holden and Vistra Energy

Corp.

10.22 — Employment  Agreement  between  Stephanie  Zapata  Moore  and 

Vistra Energy Corp.

10.23 — Employment  Agreement  between  Carrie  Lee  Kirby  and  Vistra

Energy Corp.

— Agreement between Scott A. Hudson, Vistra Energy Corp. and TXU

Retail Service Company

— Agreement between Stephen J. Muscato, Vistra Energy Corp. and 

Luminant Energy Company LLC

10.24 — Employment Agreement between Sara Graziano and Vistra Energy

Corp.

10.26 — Form of indemnification agreement with directors

10.29 — Stock Purchase Agreement, dated as of October 25, 2016, by and 
between TCEH Corp. (now known as Vistra Energy Corp.) and Curtis
A. Morgan

Credit Agreements and Related Agreements

333-215288
Form S-1 
(filed December 23, 2016)

333-215288
Form S-1 
(filed December 23, 2016)

333-215288
Amendment No. 1 
to Form S-1
(filed February 14, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

001-38086
Form 8-K 
(filed August 17, 2017)

10.1 — Credit Agreement, dated as of October 3, 2017

10.2 — Amendment to Credit Agreement, dated December 14, 2016, by and 
among  Deutsche  Bank AG  New  York  Branch,  Vistra  Operations
Company  LLC, Vistra  Intermediate  Company  LLC  and  the  other 
Credit Parties and Lenders party thereto.

10.3 — Second Amendment to Credit Agreement, dated February 1, 2017,
by  and  among  Deutsche  Bank  AG  New  York  Branch,  Vistra 
Operations Company LLC, Vistra Intermediate Company LLC and 
the other Credit Parties and Lenders party thereto.

10.4 — Third Amendment to Credit Agreement, dated February 28, 2017, by
and among Deutsche Bank AG New York Branch, Vistra Operations
Company  LLC, Vistra  Intermediate  Company  LLC  and  the  other 
Credit Parties and Lenders party thereto.

10.1 — Fourth Amendment to Credit Agreement, dated as of August 17, 2017
(effective August 17, 2017), by and among Deutsche Bank AG New 
York Branch, Vistra Operations Company LLC, Vistra Intermediate
Company LLC and the other Credit Parties and Lenders party thereto.

190

10.29

10.30

10.31

10.32

10.33

10.34

10.35

10.36

10.37

10.38

Exhibits

10.28

Previously Filed With File
Number*

001-38086
Form 8-K 
(filed December 14, 2017)

001-38086
Form 8-K 
(filed February 22, 2018)

001-38086
Form 8-K 
(filed June 15, 2018)

As
Exhibit
10.1 — Fifth Amendment to Credit Agreement, dated as of December 14,
2017 (effective December 14, 2017), by and among Deutsche Bank 
AG  New  York  Branch,  Vistra  Operations  Company  LLC,  Vistra
Intermediate Company LLC and the other Credit Parties and Lenders
party thereto.

10.1 — Sixth Amendment  to  Credit Agreement,  dated  as  of  February  20,
2018 (effective February 20, 2018), by and among Deutsche Bank 
AG  New  York  Branch,  Vistra  Operations  Company  LLC,  Vistra
Intermediate Company LLC and the other Credit Parties and Lenders
party thereto.

10.1 — Seventh Amendment to Credit Agreement, dated as of June 14, 2018,
by and among Vistra Operations Company LLC, Vistra Intermediate
Company LLC, the other Credit Parties party thereto, Credit Suisse
and Citibank, N.A. as the 2018 Incremental Term Loan Lenders, the
various  other  Lenders  party  thereto,  Credit  Suisse  as  Successor 
Administrative  Agent  and  as  Successor  Collateral  Agent,  and 
Delaware Trust Company, as Collateral Trustee.

001-38086
Form 8-K
(filed on August 7, 2018)

10.1 — Purchase Agreement,  dated August  7,  2018,  by  and  among Vistra
Operations Company LLC and Citigroup Global Markets Inc., on 
behalf of itself and the several Initial Purchasers named in Schedule
I to the Purchase Agreement

001-38086
Form 8-K
(filed on January 24, 2019)

10.1 — Purchase Agreement, dated January 22, 2019, by and among Vistra 
Operations  Company  LLC  and  J.P.  Morgan  Securities  LLC.  On 
behalf of itself and the several Initial Purchasers named in Schedule
I to the Purchase Agreement

001-38086
Form 8-K
(filed on April 9, 2018)

001-38086
Form 8-K
(filed on April 9, 2018)

001-38086
Form 8-K
(filed on April 9, 2018)

001-38086
Form 8-K
(filed on April 9, 2018)

Other Material Contracts
333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

001-38086
Form 8-K
(filed on June 15, 2018)

Assumption Agreement, dated as of April 9, 2018, between Vistra 
Energy Corp. (as successor by merger to Dynegy Inc.), and Credit 
Suisse AG, Cayman Islands Branch, as Administrative Agent and as
Collateral Trustee.

Guarantee  and  Collateral Agreement,  dated  as  of April  23,  2013,
among Dynegy Inc., the subsidiaries of the borrower from time to
time party thereto and Credit Suisse AG, Cayman Islands Branch, as
Collateral Trustee (incorporated by reference to Exhibit 10.2 to the
Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013).

Joinder, dated as of April 9, 2018, among Vistra Energy Corp., the
subsidiary guarantors party thereto and Credit Suisse AG, Cayman
Islands Branch, as Collateral Trustee.

Collateral Trust and Intercreditor Agreement, dated as of April 23,
2013 among Dynegy, the Subsidiary Guarantors (as defined therein),
Credit  Suisse AG,  Cayman  Islands  Branch  and  each  person  party
thereto from time to time (incorporated by reference to Exhibit 10.3
to the Current Report on Form 8-K of Dynegy Inc. filed on April 24,
2013).

10.10

10.11

10.12

10.13

10.5 — Collateral  Trust Agreement,  dated  as  of  October  3,  2016,  by  and 
among  TEX  Operations  Company  LLC  (now  known  as  Vistra 
Operations LLC), the Grantors from time to time thereto, Railroad 
Commission of Texas, as first-out representative, and Deutsche Bank 
AG, New York Branch, as senior credit agreement representative

10.2 — Amendment to Collateral Trust Agreement, effective as of June 14,
2018, among Vistra Operations Company LLC, the other Grantors
from time to time party thereto, Railroad Commission of Texas, as
first-out  representative,  and  Credit  Suisse  AG,  Cayman  Islands
Branch,  as  senior  credit  agreement  agent,  and  Delaware  Trust 
Company, as Collateral Trustee

191

Exhibits

10.39

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on June 15, 2018)

10.40

10.41

10.42

10.43

10.44

10.45

10.46

10.47

10.48

10.49

10.50

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

333-215288
Amendment No. 2 
to Form S-1
(filed April 5, 2017)

001-38086
Form 8-K 
(filed July 7, 2017)

001-38086
Form 8-K 
(filed October 31, 2017)

001-38086
Form 8-K 
(filed October 31, 2017)

As
Exhibit
10.3 — Collateral Trust Joinder, dated June  14, 2018, between the Additional
Grantors party thereto and Delaware Trust Company, as Collateral
Trustee, to the Collateral Trust Agreement, effective pursuant to the
Seventh Amendment as of June 14, 2018, among Vistra Operations 
Company LLC, the other Grantors from time to time party thereto,
Railroad Commission of Texas, as First-Out Representative, Credit 
Suisse AG,  Cayman  Islands  Branch,  as  Senior  Credit Agreement 
Agent, and Delaware Trust Company, as Collateral Trustee.

10.13 — Tax Receivable Agreement, by and between TEX Energy LLC (now
known as Vistra Energy Corp.) and American Stock Transfer & Trust 
Company, as transfer agent, dated as of October 3, 2016

10.14 — Tax  Matters Agreement,  by  and  among  TEX  Energy  LLC  (now
known  as  Vistra  Energy  Corp.),  Energy  Future  Holdings  Corp.,
Energy Future Intermediate Holding Company LLC, EFI Finance
Inc. and EFH Merger Co. LLC, dated as of October 3, 2016

10.15 — Transition  Services  Agreement,  by  and  between  Energy  Future
Holdings Corp. and TEX Operations Company LLC (now known as 
Vistra Operations Company LLC), dated as of October 3, 2016

10.16 — Separation Agreement,  by  and  between  Energy  Future  Holdings
Corp., TEX Energy LLC (now known as Vistra Energy Corp.) and 
TEX Operations Company LLC (now known as Vistra Operations
LLC), dated as of October 3, 2016

10.17 — Purchase and Sale Agreement, dated as of November 25, 2015, by
and  between  La  Frontera  Ventures,  LLC  and  Luminant  Holding
Company LLC

10.18 — Amended and Restated Split Participant Agreement, by and between
Oncor Electric Delivery Company LLC (f/k/a TXU Electric Delivery
Company) and TEX Operations Company LLC (now known as Vistra
Operations Company LLC), dated as of October 3, 2016

10.27 — Lease Agreement,  dated  February  14,  2002,  between  State  Street 
Bank and Trust Company of Connecticut, National Association, an
owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust,
as lessor and EFH Properties Company (now known as Vistra EP 
Properties Company), as Lessee (Energy Plaza Property)

10.28 — First Amendment, dated June 1, 2007, to Lease Agreement, dated 

February 14, 2002

10(a) — Asset Purchase Agreement, dated as of July 5, 2017, by and among 
Odessa-Ector  Power  Partners,  L.P.,  La  Frontera  Holdings,  LLC,
Vistra Operations Company LLC, Koch Resources, LLC

10.1 — Merger Support Agreement, dated as of October 29, 2017, by and 

between Vistra Energy Corp. and Terawatt Holdings, LP

10.2 — Merger Support Agreement, dated as of October 29, 2017, by and 
among Vistra Energy Corp. and Oaktree Opportunities Fund VIII,
Investment  Fund,  L.P.,  Oaktree
L.P.,  Oaktree  Huntington 
Opportunities  Fund  VIII  (Parallel  2),  L.P.,  Oaktree  Opportunities
Fund VIIIb, L.P., Oaktree Opportunities Fund IX, L.P. and Oaktree
Opportunities Fund IX (Parallel 2), L.P.

192

Exhibits

10.51

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on August 23, 2018)

As
Exhibit
10.1 — Amendment  No.  1  to  Registration  Rights Agreement  dated  as  of 
August 22, 2018, by and among the Company and the Guarantors
(as defined therein)

Subsidiaries of the Registrant

**

Consent of Experts

**

— Significant Subsidiaries of Vistra Energy Corp.

— Consent of Deloitte & Touche LLP

Rule 13a-14(a) / 15d-14(a) Certifications

(21)

21.1

(23)

23.1

(31)

31.1

31.2

(32)

32.1

32.2

(95)

95.1

**

**

Section 1350 Certifications

**

**

Mine Safety Disclosures

**

XBRL Data Files

101.INS

**

101.SCH **

101.CAL

101.DEF

**

**

101.LAB **

101.PRE

**

____________________
* 
**  Filed herewith

Incorporated herein by reference

Item 16.  FORM 10-K SUMMARY

Not applicable.

— Certification  of  Curtis A.  Morgan,  principal  executive  officer  of 
Vistra Energy Corp., pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002

— Certification  of  J.  William  Holden,  principal  financial  officer  of 
Vistra Energy Corp., pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002

— Certification  of  Curtis A.  Morgan,  principal  executive  officer  of 
Vistra Energy Corp., pursuant to U.S.C. Section 1350, as adopted 
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

— Certification  of  J.  William  Holden,  principal  financial  officer  of 
Vistra Energy Corp., pursuant to U.S.C. Section 1350, as adopted 
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

— Mine Safety Disclosures

— XBRL Instance Document

— XBRL Taxonomy Extension Schema Document

— XBRL Taxonomy Extension Calculation Document

— XBRL Taxonomy Extension Definition Document

— XBRL Taxonomy Extension Labels Document

— XBRL Taxonomy Extension Presentation Document

193

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Vistra Energy Corp. has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 28, 2019

VISTRA ENERGY CORP.
By

/s/ CURTIS A. MORGAN
Curtis A. Morgan (President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of Vistra Energy Corp. and in the capacities and on the date indicated.

Signature

g

Title

Date

/s/ CURTIS A. MORGAN
(Curtis A. Morgan, President and Chief Executive Officer)

Principal Executive Officer
and Director

February 28, 2019

/s/ J. WILLIAM HOLDEN
(J. William Holden, Executive Vice President and Chief Financial
Officer)

Principal Financial Officer

February 28, 2019

/s/ CHRISTY DOBRY
(Christy Dobry, Vice President and Controller)

/s/ SCOTT B. HELM
(Scott B. Helm, Chairman of the Board)

/s/ HILARY E. ACKERMANN
(Hilary E. Ackermann)

Principal Accounting Officer

February 28, 2019

Chairman of the Board and
Director

February 28, 2019

Director

February 28, 2019

/s/ GAVIN R. BAIERA
(Gavin R. Baiera)

/s/ PAUL M. BARBAS
(Paul M. Barbas)

/s/ BRIAN K. FERRAIOLI
(Brian K. Ferraioli)

/s/ JEFF D. HUNTER
(Jeff D. Hunter)

/s/ CYRUS MADON
(Cyrus Madon)

/s/ GEOFFREY D. STRONG
(Geoffrey D. Strong)

/s/ JOHN R. SULT
(John R. Sult)

/s/ BRUCE ZIMMERMAN
(Bruce Zimmerman)

Director

February 28, 2019

Director

February 28, 2019

Director

February 28, 2019

Director

February 28, 2019

Director

February 28, 2019

Director

February 28, 2019

Director

February 28, 2019

Director

February 28, 2019

194

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[THIS PAGE INTENTIONALLY LEFT BLANK]

Stockholder Information

Stock Exchange Listing

NYSE: VST

Corporate Headquarters

Vistra Energy Corp. 

6555 Sierra Drive 

Irving, Texas 75039

Board of Directors † 

Hilary E. Ackermann (4)*

Gavin R. Baiera (2)*

Paul M. Barbas (2,3)

Brian K. Ferraioli (1)*

Scott B. Helm, Chairman of the Board of Directors 

Stock Transfer Agent and Registrar

Please direct general questions about stockholder accounts, 

(cid:90)(cid:91)(cid:86)(cid:74)(cid:82)(cid:3)(cid:74)(cid:76)(cid:89)(cid:91)(cid:80)(cid:196)(cid:74)(cid:72)(cid:91)(cid:76)(cid:90)(cid:19)(cid:3)(cid:91)(cid:89)(cid:72)(cid:85)(cid:90)(cid:77)(cid:76)(cid:89)(cid:3)(cid:86)(cid:77)(cid:3)(cid:90)(cid:79)(cid:72)(cid:89)(cid:76)(cid:90)(cid:19)(cid:3)(cid:86)(cid:89)(cid:3)(cid:75)(cid:92)(cid:87)(cid:83)(cid:80)(cid:74)(cid:72)(cid:91)(cid:76)(cid:3)(cid:84)(cid:72)(cid:80)(cid:83)(cid:80)(cid:85)(cid:78)(cid:90)(cid:3) 
to Vistra Energy’s transfer agent:

(cid:49)(cid:76)(cid:584)(cid:3)(cid:43)(cid:21)(cid:3)(cid:47)(cid:92)(cid:85)(cid:91)(cid:76)(cid:89)(cid:3)(2,4)

Cyrus Madon (3)

Curtis A. Morgan

American Stock Transfer & Trust Company, LLC 

(cid:46)(cid:76)(cid:86)(cid:584)(cid:89)(cid:76)(cid:96)(cid:3)(cid:43)(cid:21)(cid:3)(cid:58)(cid:91)(cid:89)(cid:86)(cid:85)(cid:78)(cid:3)(3)

John R. Sult (1,4)

Bruce E. Zimmerman (1)

1 Audit Committee

2 Compensation Committee

3 Nominating and Governance Committee

4 Risk Committee

* Committee Chair

†  As of March 31, 2019. Besides Curtis A. Morgan, all members of the Vistra 
Energy Board of Directors satisfy the independence requirements of the 
Securities and Exchange Commission and the NYSE.

6201 15th Avenue 

Brooklyn, NY 11219 

Phone: (800) 937-5449 

Email: info@amstock.com

Independent Registered Accounting Firm

Deloitte & Touche LLP

(cid:54)(cid:585)(cid:74)(cid:76)(cid:89)(cid:3)(cid:42)(cid:76)(cid:89)(cid:91)(cid:80)(cid:196)(cid:74)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:90)

(cid:54)(cid:92)(cid:89)(cid:3)(cid:40)(cid:85)(cid:85)(cid:92)(cid:72)(cid:83)(cid:3)(cid:57)(cid:76)(cid:87)(cid:86)(cid:89)(cid:91)(cid:3)(cid:86)(cid:85)(cid:3)(cid:45)(cid:86)(cid:89)(cid:84)(cid:3)(cid:24)(cid:23)(cid:20)(cid:50)(cid:3)(cid:196)(cid:83)(cid:76)(cid:75)(cid:3)(cid:94)(cid:80)(cid:91)(cid:79)(cid:3)(cid:91)(cid:79)(cid:76)(cid:3)(cid:58)(cid:44)(cid:42)(cid:3) 
is included herein, excluding all exhibits other than our 

(cid:58)(cid:72)(cid:89)(cid:73)(cid:72)(cid:85)(cid:76)(cid:90)(cid:20)(cid:54)(cid:95)(cid:83)(cid:76)(cid:96)(cid:3)(cid:40)(cid:42)(cid:59)(cid:3)(cid:58)(cid:76)(cid:74)(cid:91)(cid:80)(cid:86)(cid:85)(cid:3)(cid:26)(cid:23)(cid:25)(cid:3)(cid:72)(cid:85)(cid:75)(cid:3)(cid:32)(cid:23)(cid:29)(cid:3)(cid:74)(cid:76)(cid:89)(cid:91)(cid:80)(cid:196)(cid:74)(cid:72)(cid:91)(cid:80)(cid:86)(cid:85)(cid:90)(cid:3) 
by the CEO and CFO. We will send stockholders copies  

of the exhibits to our Annual Report on Form 10-K and  

any of our corporate governance documents, free of  

charge, upon request.

Note that these documents, along with further information 

about our company, board of directors, management  

team and contact details, are available on our website at 

www.vistraenergy.com.

Vistra Energy Corp.  |  6555 Sierra Drive, Irving, Texas 75039  |  www.vistraenergy.com