Vistra Annual Report 2021

FY2021 Annual Report · Vistra
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2021

A N N U A L

  R E

P O R T

Powering a Better Way Forward: Chicago

For decades, one of Vistra’s premier retail brands, Dynegy, has served 

millions of customers across the Midwest and Northeast, and we’re  

excited to power some of Chicago’s most beloved and iconic sites,  

including Wrigley Field and Willis Tower.

Wrigley Field

Dynegy is the Official and Exclusive Energy Provider for the Chicago  

Cubs and Wrigley Field. Dynegy is committed to delivering best-in-class 

service and powering the gameday experience for fans visiting Chicago’s 

beloved Wrigley Field. Dynegy understands the unique operational needs  

of professional sports facilities and is committed to creating tailored 

solutions that work for each of its customers.

Willis Tower

Sustainability is a shared top priority for Dynegy and Chicago’s  

iconic Willis Tower. As the retail electric supplier for the 110-story tower,  

Dynegy provides 100% renewable electricity, supporting the building’s 

sustainability goals. Dynegy is proud to power the historic Willis Tower 

and serve the millions of people who work and visit it each year. 

Vistra has established itself as a leader  
in ESG and the clean energy transition 
with our Vistra Zero carbon-free  
generation portfolio and our many  
green retail products and solutions  
we offer to customers. 

Curt Morgan
Chief Executive Officer

By year-end, we had delivered squarely on each
of these four strategic imperatives, and I’ll touch 
on each in the following pages to highlight our
performance in 2021 and the prospects for the
future of our company. 

Accelerating our Zero-Carbon Growth  
Pipeline with Cost-Effective Capital

Vistra has established itself as a leader in ESG and 
the clean energy transition with our Vistra Zero 
carbon-free generation portfolio and our many
green retail products and solutions we offer to 
customers. We continue to focus on opportunities 
to grow our business responsibly through 
economically attractive investments that contribute 
to our decarbonization goals, including achieving 
net zero by 2050, while also delivering commen-
surate returns and value for all stakeholders. In
2021, we reinforced our commitment to growing 
our renewable and battery storage portfolio to 
support the broader decarbonization of the U.S. 
economy, maintain the reliability and affordability of 
electricity, and enhance the long-term sustainability 
of Vistra.

In December, we published our Green Finance 
Framework, which enables us to issue green 
ﬁnancial instruments to fund new or existing 
renewable and energy efficiency projects. We then
successfully launched an attractively priced and 
upsized $1 billion of Green Perpetual Preferred 

Dear Fellow Vistra Stockholders,

t d

f d di

There is no doubt that 2021 was a challenging year;
however, in many ways, 2021 was also a pivotal
one. We began the year facing the hardships
presented by Winter Storm Uri (Uri), but with our 
team of dedicated employees, we came together 
l
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to not only confront and mitigate the impact but 
also grow from the experience. Back in 2016, when
Vistra emerged from bankruptcy we embarked on a
strategy emphasizing a strong balance sheet as one
of the cornerstones of the company. That strategic 
priority enabled us to withstand Uri and get back 
on track in a relatively short period of time. 

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t

After understanding the full impact of Uri, we 
began a comprehensive process in the second
quarter of 2021 to review our strategic direction
and approach to capital allocation. As a result of 
this process, we identiﬁed and prioritized four key 
strategic imperatives:

1. Accelerating our zero-carbon growth pipeline 

with cost-effective capital

2. Returning signiﬁcant capital to stockholders from

our core business

3. Maintaining a strong balance sheet

4. Driving long-term, sustainable value through 

Vistra’s integrated business model

VISTRA 2021 ANNUAL REPORT

1

Stock—the ﬁrst green preferred stock offering from 
a U.S. corporate issuer—to fund existing and new
eligible green projects, including our renewable and
battery storage development projects. Ultimately, 
this capital infusion will fund a portion of the
development pipeline of several zero-carbon
projects in our Vistra Zero portfolio in a cost-
effective manner.

In connection with the Green Perpetual Preferred 
Stock offering, we announced our intention to
grow Vistra Zero to at least 7,300 megawatts by 
2026, with ~2,900 MW currently online (including
our 2,300 MW low-cost nuclear facility, Comanche
Peak). The $5 billion investment in Vistra Zero 
through 2026 is projected to contribute $450–$500
million of Adjusted EBITDA1 annually by year-end 
2026 (in addition to Adjusted EBITDA1 generated
by Comanche Peak). We intend to fund these
development projects primarily through project
ﬁnancing, supplemented by Vistra Zero project 
cash ﬂows and the net proceeds of the Green 
Perpetual Preferred Stock offering. Vistra’s green
and sustainable growth strategy through Vistra
Zero is bolstered by our ability to use our existing
sites, including repurposing retired or to-be-retired
sites, which have existing access to transmission 
infrastructure.

Key development announcements and progress  
of our Vistra Zero projects in 2021 include: 

In California:

• Moss Landing Energy Storage Facility continues 
to expand—Phases I (300 MW) and II (100 MW)
both achieved commercial operations in 2021,
and in February 2022, we announced further
expansion through Phase III (350 MW), bringing 
the site’s total energy storage capacity to 750
MW/3,000 MWh. We have the potential to 
eventually reach 1,500 MW, supporting the state 
of California’s electricity needs. We experienced
certain operational delays as the water-based
heat suppression systems improperly leaked water
on a small percentage of the battery modules,
temporarily taking Phases I and II offline. However, 
we have identiﬁed the issues, are taking corrective
actions, and expect to be storing and releasing
energy to support California’s grid during the
all-important 2022 summer season.

VISTRA 2021 ANNUAL REPORT

2

In Illinois:

• A three-year effort culminated in the passage of 
an omnibus energy package that included our
Illinois Coal to Solar & Energy Storage Initiative. 
As enacted, the legislation supports Vistra’s future 
construction and operation of up to 300 MW of 
utility-scale solar and 150 MW of battery energy 
storage facilities at nine retired or to-be-retired 
coal plant sites across central and southern Illinois. 
The initiative will also include diverse suppliers 
while bringing a much-needed property tax base
to local communities. 

In Texas:

• Our Electric Reliability Council of Texas (ERCOT)

1,000 MW Phase I projects, announced in 
September 2020, took shape with three projects
scheduled to achieve commercial operations prior
to summer 2022:

50 MW Brightside Solar Facility

108 MW Emerald Grove Solar Facility

260 MW DeCordova Energy Storage Facility

• We also grew the Vistra Zero portfolio in Texas by 
acquiring the to-be-constructed 110 MW Angus 
Solar Facility, expected online in 2023.

We believe Vistra is exactly the kind of company 
that should be embraced as a leader in the energy
transition—our track record includes responsibly 
and justly retiring carbon-emitting resources, 
reclaiming sites, and investing in new green 
technology and resources. Since 2010, Vistra has 
retired more than 12,000 MW of coal and gas power 
plants, resulting in a 45% reduction of greenhouse
gas (GHG) emissions through year-end 2020, 
compared to a 2010 baseline. Additionally, we have 
announced the expected retirement of nearly 8,000
MW of additional fossil-fueled power plants by
2027, for a total of ~20,000 MW since 2010, with 
plans to repurpose feasible sites to solar and energy 
storage developments. We are conﬁdent that our 
diversiﬁed asset mix will support the reliability of
the electric system while providing customers with 
affordable energy that meets their sustainable 
preferences throughout the clean energy transition.

Vistra Zero carbon-free generation portfolio includes solar  
(Upton 2 Solar Facility, left), nuclear (Comanche Peak Power 
Plant, right), and battery storage (DeCordova Energy Storage 
Facility, below).

We believe Vistra is exactly the kind of  
company that should be embraced as a 
leader in the energy transition.

Returning Signiﬁcant Capital to Stockholders 

Our long-term capital allocation plan reﬂects an
anticipated return of capital of at least $7.5 billion to 
our common stockholders through year-end 2026.
In October 2021, our board of directors approved
a $2 billion share repurchase program, which we
are on track to fully execute by year-end 2022.
The share repurchase program is partially funded
by the $1 billion of 8% preferred equity we issued 
in October 2021, and as announced on our fourth
quarter 2021 earnings call, Vistra had repurchased 
~$764 million of the $2 billion as of Feb. 22, 2022,
resulting in a 7% reduction in shares outstanding 
since our previously reported share count as of 
Nov. 2, 2021. Once we conclude this initial $2 billion
share repurchase plan, we then expect to allocate
at least an average of $1 billion per year toward
share repurchases from 2023 through 2026 for a
total of at least $6 billion in ﬁve years. Vistra’s core 
business is expected to generate on average $3+
billion per year of Adjusted EBITDA1 and we expect 
to convert 60–70%+ of Adjusted EBITDA1 to free
cash ﬂow, affording the signiﬁcant cash ﬂow to 
return to shareholders, especially since the Vistra 
Zero growth will be funded by internally generated 
Vistra Zero cash ﬂow and third-party capital. Hence, 
our philosophy is simple and straight forward—for
as long as we believe our stock is undervalued, we 
will dedicate signiﬁcant cash ﬂow from our core
business to repurchase our shares. 

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Our capital allocation plan also reinforced our
O
commitment to pay a meaningful and growing
c
dividend. In October 2021, we announced our
d
i
ntent to allocate $300 million per year toward 
our common dividend. We anticipate this dividend 
o
policy will offer greater dividend yield growth for 
p
stockholders rather than identifying a target annual
s
g
growth rate as we retire shares through our ongoing 
repurchases. This $300 million dividend pool will
be spread over fewer shares, providing growth in 
dividend yield on the remaining shares. Our ﬁrst 
quarter 2022 dividend of $0.17 per share of Vistra’s 
common stock, represents a ~13% increase in the 
company’s quarterly common stock dividend per 
share from its ﬁrst quarter 2021 dividend.

Maintaining a Strong Balance Sheet

Vistra has always focused on a strong balance 
sheet, and it will remain a priority. A strong balance 
sheet provided the support we needed to withstand 
the hardships brought by Uri. Immediately following 
Uri, we executed ﬁnancing transactions to support
our liquidity needs, increasing our net debt by just 
over $2 billion. However, just a few months later,
we announced as part of our capital allocation plan
that we expect to further reduce corporate-level 
debt by ~$1.5 billion by year-end 2022 with plans 
to retire up to ~$3 billion of corporate-level debt
in ﬁve years. By year-end 2021, we had already 
decreased corporate-level debt by ~$625 million
and we believe we will approach pre-Uri debt levels
by year-end 2022. We project that we will be able
to maintain leverage in our current range of 3–3.5
times net debt to Adjusted EBITDA1 in the near-
term and reach the mid- to high-2s over the next 
ﬁve years, exclusive of the leverage to support the
Vistra Zero growth.

Driving Long-Term, Sustainable Value 
Through Vistra’s Integrated Business Model

Vistra’s integrated model—a best-in-class 
generation ﬂeet and premier retail business that 
we have grown and expanded over the past ﬁve
years—provides the foundation and cash ﬂow that
support the three strategic priorities detailed above. 

We have always believed in the value of our
integrated operations, and we remain conﬁdent 
that the pairing of our low-cost, efficient, and 
diversiﬁed generation ﬂeet—including our growing
zero-carbon business—with our customer-centric 
retail platform and best-in-class commercial 
capabilities is the optimal way to maintain resiliency
and create value for our stockholders. In fact, the 
uniquely low maintenance capital and operations 
and maintenance expense required to produce 
the $3 billion+ of Adjusted EBITDA1 affords us a
signiﬁcant amount of free cash ﬂow to support a
diverse capital allocation plan with an emphasis on
returning capital to ﬁnancial stakeholders.

Financial Execution

We entered 2021 on the heels of an outstanding 
2020 where we achieved results above the high end 
of our raised guidance range and marked the ﬁfth
year in a row that our ﬁnancial results exceeded the 
midpoint of our Adjusted EBITDA from Ongoing
Operations1 guidance range. Uri led to a conﬂuence 
of unpredictable events, exposing issues with the 
integrated natural gas and electric systems in the 
Texas ERCOT market, including impaired gas
deliverability, challenging the ﬁnancial strength 
we had worked hard to put in place. We faced 
the challenge and stabilized the company, and
then immediately got back to work signiﬁcantly 
offsetting the Uri ﬁnancial impact and getting the
company back on the path of exceptional perfor-
mance and creating long-term shareholder value.

To mitigate the ﬁnancial impact of Uri, we 
identiﬁed various self-help initiatives, including
the monetization of certain commercial positions,
optimizing spend on our generation O&M project 
work, retail cost savings and margin performance, 
and support group cost savings, culminating in
value creation that exceeded our $500 million
target. In addition, we have also been very active in

VISTRA 2021 ANNUAL REPORT

4

the Texas 2021 legislative and ongoing regulatory
deliberations regarding Uri, which, among other
accomplishments, resulted in Vistra being allocated
~$544 million in ERCOT securitization payments. 
The self-help and securitization efforts resulted 
in an improvement following Uri of over $1 billion. 
These efforts also helped de-risk the integrated
Texas natural gas and power systems reducing the
potential volatility in the Texas ERCOT market and
Vistra’s ﬁnancial and operating performance.

In the end, we reported 2021 Adjusted EBITDA from 
Ongoing Operations1 of $1,941 million, including
the impacts from Uri-related retail bill credit settle-
ments resulting in high returns to Vistra. Excluding
the $53 million related to these settlements, 2021
Adjusted EBITDA from Ongoing Operations1 was 
$1,994 million, slightly favorable to the November
revised and tightened midpoint of guidance. 
Under very difficult circumstances following Uri,
we executed and accomplished exactly what we 
set out to do: stabilize the company and recover 
as much lost value as possible in order to put our
company back on track to maximize our ﬁnancial 
results for our stockholders.

Generation

During the week of Uri, our Texas generation ﬂeet, 
which makes up 18% of the capacity available in 
ERCOT, provided between 25–30% of the power
on the grid, far exceeding our market share.
Unfortunately, the ﬁnancial results did not match 
this performance due to the failures of the natural
gas system and the uneven allocation of customer 
curtailments in ERCOT. Our employees went to
extraordinary efforts, working around-the-clock 
in sub-freezing temperatures to keep our assets
running and to maintain and restore power for 
the people of Texas. This was achieved while also
effectively managing COVID-19 at all plant sites 
and constantly tracking and adjusting to CDC and
OSHA recommendations. Vistra ﬁnished the year 
with commercial availability, a measure of the ﬂeet’s 
ability to meet demand during the highest margin
hours, of ~92%—very strong performance for a ﬂeet 
with the characteristics of ours.

In 2021, Vistra continued our operations 
performance improvement (OPI) initiative, realizing

Vistra’s ﬂagship retail brand, TXU Energy, launched a 
product speciﬁcally for electric vehicle owners, giving 
customers 50% off energy charges every weeknight and 
all weekend long—times when customers most often 
charge their vehicles. 

$500 million of savings—a $275 million increase 
from the 2018 projection established with the 
Dynegy merger. OPI is now a part of our DNA with
continuous idea generation and conversion of ideas
to executable opportunities on a regular basis.
Focused on learnings from Uri, we enhanced and 
further de-risked our ﬂeet by investing more than
$50 million in 2021, with execution beginning on
another $30 million in 2022. These expenditures
include the addition of onsite backup fuel at six
plants with enough fuel for several days, additional 
offsite gas storage, and several actions to guard
against severe weather impacts on critical 
equipment.

Our people are our most important asset, and
their safety is our highest priority. Vistra’s plants
operated safely throughout the year—a testament
to our “Best Defense” mindset which puts safety
above all else. Through the team’s efforts, Vistra 
ended the year without any serious injuries or
fatalities to our Vistra employees or business 
partners working at our sites. Our focus on
safety is further highlighted with 12 power plant 
sites achieving VPP Star status from OSHA, 
demonstrating superior efficacy of their safety and
health management systems, and maintaining injury
and illness rates below industry average. In 2021, we
introduced the VPP process to ﬁve new facilities, 
and four of our power plants submitted VPP 
applications that are awaiting OSHA review.

Retail

Vistra’s retail business rose to the challenge as 
well while maintaining our customer-centric 
approach despite the challenges of COVID-19 and 
Uri. During Uri, we assured customers they would 
be insulated from storm-related rate increases, 
donated $5 million to support our communities
in need, and provided bill-pay assistance. By year 
end, Vistra’s retail business grew ERCOT residential 
counts by ~23,000 customers, the highest organic
growth we’ve seen since 2008. Most of this growth 
was within our ﬂagship retail brand TXU Energy,
demonstrating the strength of our brand promise
and continued importance to our customers.

This was also a standout year for our two largest 
retail brands, with the launch of several ﬁrst-to-
market customer-centric products and others 

VISTRA 2021 ANNUAL REPORT

5

Our people are our most important  
asset and their safety is our highest  
priority. Vistra’s plants operated safely 
throughout the year—a testament to  
our “Best Defense” mindset which  
puts safety above all else. 

designed for increased use of electricity to 
fuel vehicles.

• Ambit’s Winter Break plan gives customers in the 
Midwest and Northeast savings when they need it
most by offering 50% off all winter long.

• Ambit Energy Bank gives Texas customers year-

round control and predictability.

• TXU Energy continued to broaden its most

imitated product portfolio with the launch of TXU
Energy Freedom Rewards. This ﬁrst-of-its-kind 
plan allows customers to earn 30% in free
electricity for every dollar they spend on energy
charges, automatically, all year long.

• TXU Energy EV Pass is designed speciﬁcally for 

electric vehicle owners.

Innovation remains a pillar of our retail business. As 
electric vehicle adoption takes off, we’ll continue to
develop products and partnerships to attract this
important segment of customers. Additionally, we 
saw an increase in customers buying more than just
electricity from us in 2021, growing our business of
value-added products such as HVAC maintenance, 
home warranties, and surge protection plans. 
Vistra’s approach to value-added services has been
to partner with companies providing these services, 
earning a percentage of margin, rather than owning 
and competing in these businesses which have
their own challenges and require their own sets
of capabilities. This approach also allows us to be 
nimble and make changes while improving our
offerings if the situation dictates. We believe this 
is the most cost-effective manner to broaden our
product offering and protect our balance sheet
and brands.

From the world’s largest battery energy storage facility to miles and miles 
of solar panels, Vistra Zero is bringing a zero-carbon future to life.

SOLAR

ENERGY STORAGE

SOLAR + ENERGY STORAGE

DeCordova Energy Storage Facility
260 MW
Hood County, TX

Edwards Energy Storage Facility
37 MW
Peoria County, IL

Havana Energy Storage Facility
37 MW
Mason County, IL

Joppa Energy Storage Facility
37 MW
Massac County, IL

Moss Landing Energy Storage Facility
750 MW/3,000MWh 
Moss Landing, CA

Oakland Energy Storage Facility
43.25 MW
Oakland, CA

Andrews Solar Facility
100 MW
Andrews County, TX

Angus Solar Facility
110 MW
Bosque County, TX

Brightside Solar Facility
50 MW
Live Oak County, TX

Emerald Grove Solar Facility
108 MW
Crane County, TX

Forest Grove Solar Facility
200 MW
Henderson County, TX

Oak Hill Solar Facility
200 MW
Rusk County, TX

NUCLEAR

Comanche Peak Nuclear Power Plant
2,300 MW
Somervell County, TX

VISTRA 2021 ANNUAL REPORT

6

Baldwin Solar & Energy Storage Facility
68 MW solar; 9 MW battery
Randolph County, IL

Coffeen Solar & Energy Storage Facility
44 MW solar; 6 MW battery
Montgomery County, IL

Duck Creek Solar & Energy Storage 
Facility
20 MW solar; 3 MW battery
Fulton County, IL

Hennepin Solar & Energy Storage 
Facility
50 MW solar; 6 MW battery
Putnam County, IL

Kincaid Solar & Energy Storage Facility
60 MW solar;  MW battery
Christian County, IL

Newton Solar & Energy Storage Facility
52 MW solar; 7 MW battery
Jasper County, IL

Upton 2 Solar & Energy Storage Facility
180 MW solar; 10 MW/42 MWh battery
Upton County, TX

List includes publicly announced projects
under development

ESG Accomplishments

Conclusion

Before I close, while our business portfolio 
transformation is a key element of our sustainability 
strategy, I would be remiss if I did not highlight 
other ESG accomplishments we achieved this year:

• Named one of America’s Most JUST Companies,
by JUST Capital and its media partner CNBC, for
a commitment to serving workers, customers, 
communities, the environment, and stockholders.

• Honored with 2021 Texan by Nature 20

designation by the conservation non-proﬁt Texan
by Nature for a demonstrative commitment to
conservation and sustainability.

• Received the 2021 Excellence in Surface Coal
Mining Reclamation Award from the Office of
Surface Mining Reclamation & Enforcement, a
bureau of the U.S. Department of the Interior, for
work done to reclaim and restore previously mined 
land at Monticello-Winﬁeld Mine. The award 
recognizes companies that achieve the most
exemplary coal mine reclamation in the nation.

• Joined Disability:IN, the leading non-proﬁt

resource for business disability inclusion world-
wide, reinforcing commitment to equality and
inclusion at Vistra.

• Continued year two of a ﬁve-year, $10 million
commitment to support organizations that
grow minority-owned small businesses, enhance
economic development, and provide educational
opportunities for students from diverse
backgrounds.

• Advanced diversity, equity, and inclusion (DEI) 
in the workplace through strengthening internal
hiring and recruiting practices through numerous
initiatives including training for hiring managers
and partnerships with minority-serving institutions.

• Incorporated an ESG Index, with a 10% weighting, 
into Vistra’s compensation scorecard, ensuring 
accountability all the way to the top of the
company.

We continue to believe that the most effective and
sustainable companies have a well-balanced focus 
on a variety of stakeholders including you—our 
investors—and our customers, communities, people, 
and suppliers. We are supplying a vital product to 
society, and we must balance that crucial role with
our environmental footprint. In 2021, we advanced
our company in many important ways, especially 
in the areas represented by ESG. Although we 
endured an unprecedented weather event that 
resulted in a signiﬁcant ﬁnancial impact and a
temporary loss of value, we ﬁnished the year strong, 
fully recovering the loss in value of our stock from
Uri by year end. Ultimately, I am most proud of how
this company responded to the impacts from Uri,
most of which were uncontrollable, and continued
to live our core principles of doing business the
right way, competing as a team to win, and caring
for all of our stakeholders. We never wavered 
and we did not give up, and we are now back on
track with our stock price continuing to respond 
favorably to our new and improved capital
allocation plan. We cannot change what happened
during Uri, but we can and did learn from it,
de-risking and strengthening our company for the 
future. We completed 2021 with a clear strategic
direction as a leader in the clean energy transition
coupled with a capital allocation plan that we
believe will provide exceptional value to our
stockholders for years to come.

We begin 2022 from a position of strength for
which we can all be proud. It was with this strength
in mind that on March 21, 2022, I announced
that I will be transitioning the role of CEO to my 
colleague, Jim Burke. Leading Vistra has been the
most rewarding experience of my 40-year career.
I remain excited about the long-term opportunity
ahead as Vistra returns signiﬁcant capital to 
investors while transitioning our ﬂeet to lower 
carbon resources. Jim is a proven leader who 
possesses deep experience in our company 
and industry and understands the company’s 
commitment to all our stakeholders. I’m excited
to watch him lead Vistra to continued success.

Thank you for your interest in Vistra—as always,
we look forward to its future!

Curt Morgan
Chief Executive Officer

1 Adjusted EBITDA is a non-GAAP ﬁnancial measure. Please refer to the “Non-GAAP Reconciliation” table on page 8 of this Annual Report.

VISTRA 2021 ANNUAL REPORT

7

Non-GAAP Financial Measures and Forward-Looking Statements

This letter includes references to Adjusted EBITDA which is a non-GAAP ﬁnancial measure. For reconciliations between our non-GAAP
measures and the nearest GAAP measures, please refer to the table below. As non-GAAP ﬁnancial measures are not intended to be 
considered in isolation or as a substitute for GAAP ﬁnancial measures, you should carefully read the Form 10-K included in this Annual
Report, which includes our consolidated ﬁnancial statements prepared in accordance with GAAP. Additionally, this letter includes state-
ments that, to the extent they are not recitations of historical fact, constitute forward-looking statements within the meaning of the federal 
securities laws, and are based on Vistra’s current expectations and assumptions. For a discussion identifying important factors that could
cause actual results to vary materially from those anticipated in the forward-looking statements, see Vistra’s ﬁlings with the SEC including,
but not limited to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” in the
Form 10-K portion of this Annual Report.

Non-GAAP Reconciliation — 2021 Adjusted EBITDA
Year Ended December 31, 2021 (Unaudited) (Millions of Dollars)

Retail

Texas

East

West

Sunset

Eliminations/ 
Corp and 
Other

Ongoing 
Operations 
Consolidated

Asset 
Closure

Vistra 
Consolidated

Net income (loss)

2,196

(2,512)

(567)

(cid:43)(cid:80)(cid:69)(cid:81)(cid:79)(cid:71)(cid:2)(cid:86)(cid:67)(cid:90)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:2)(cid:10)(cid:68)(cid:71)(cid:80)(cid:71)(cid:386)(cid:86)(cid:11)

(cid:43)(cid:80)(cid:86)(cid:71)(cid:84)(cid:71)(cid:85)(cid:86)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:69)(cid:74)(cid:67)(cid:84)(cid:73)(cid:71)(cid:85)(cid:2)(cid:10)(cid:67)(cid:11)

(cid:38)(cid:71)(cid:82)(cid:84)(cid:71)(cid:69)(cid:75)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:67)(cid:79)(cid:81)(cid:84)(cid:86)(cid:75)(cid:92)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:10)(cid:68)(cid:11)

2

9

212

—

(cid:10)(cid:19)(cid:22)(cid:11)

686

EBITDA before Adjustments

2,419

(1,840)

(cid:55)(cid:80)(cid:84)(cid:71)(cid:67)(cid:78)(cid:75)(cid:92)(cid:71)(cid:70)(cid:2)(cid:80)(cid:71)(cid:86)(cid:2)(cid:10)(cid:73)(cid:67)(cid:75)(cid:80)(cid:11)(cid:17)(cid:78)(cid:81)(cid:85)(cid:85)(cid:2)(cid:84)(cid:71)(cid:85)(cid:87)(cid:78)(cid:86)(cid:75)(cid:80)(cid:73)(cid:2)(cid:72)(cid:84)(cid:81)(cid:79)(cid:2)
hedging transactions

(cid:10)(cid:19)(cid:14)(cid:22)(cid:18)(cid:21)(cid:11)

1,139

Generation plant retirement expenses

(cid:40)(cid:84)(cid:71)(cid:85)(cid:74)(cid:2)(cid:85)(cid:86)(cid:67)(cid:84)(cid:86)(cid:2)(cid:17)(cid:2)(cid:82)(cid:87)(cid:84)(cid:69)(cid:74)(cid:67)(cid:85)(cid:71)(cid:2)(cid:67)(cid:69)(cid:69)(cid:81)(cid:87)(cid:80)(cid:86)(cid:75)(cid:80)(cid:73)
impacts

(cid:43)(cid:79)(cid:82)(cid:67)(cid:69)(cid:86)(cid:85)(cid:2)(cid:81)(cid:72)(cid:2)(cid:54)(cid:67)(cid:90)(cid:2)(cid:52)(cid:71)(cid:69)(cid:71)(cid:75)(cid:88)(cid:67)(cid:68)(cid:78)(cid:71)(cid:2)(cid:35)(cid:73)(cid:84)(cid:71)(cid:71)(cid:79)(cid:71)(cid:80)(cid:86)

Non-cash compensation expenses

(cid:54)(cid:84)(cid:67)(cid:80)(cid:85)(cid:75)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:79)(cid:71)(cid:84)(cid:73)(cid:71)(cid:84)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:85)

(cid:49)(cid:86)(cid:74)(cid:71)(cid:84)(cid:14)(cid:2)(cid:75)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:75)(cid:80)(cid:73)(cid:2)(cid:75)(cid:79)(cid:82)(cid:67)(cid:75)(cid:84)(cid:79)(cid:71)(cid:80)(cid:86)(cid:2)(cid:81)(cid:72)(cid:2)(cid:78)(cid:81)(cid:80)(cid:73)(cid:15)
(cid:78)(cid:75)(cid:88)(cid:71)(cid:70)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:81)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:67)(cid:85)(cid:85)(cid:71)(cid:86)(cid:85)

(cid:37)(cid:49)(cid:56)(cid:43)(cid:38)(cid:15)(cid:19)(cid:27)(cid:15)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:85)(cid:2)(cid:10)(cid:69)(cid:11)

(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:75)(cid:79)(cid:82)(cid:67)(cid:69)(cid:86)(cid:85)(cid:2)(cid:10)(cid:70)(cid:11)

Adjusted EBITDA

—

2

—

—

(cid:10)(cid:20)(cid:11)

57

—

—

(cid:10)(cid:19)(cid:22)(cid:11)

—

—

—

18

4

239

457

1,312

(236)

—

737

—

15

698

146

655

—

(cid:10)(cid:25)(cid:22)(cid:11)

—

—

—

9

1

1

—

(cid:10)(cid:27)(cid:11)

60

52

38

—

—

—

—

—

3

—

—

93

(413)

—

2

139

(272)

330

18

(cid:10)(cid:23)(cid:20)(cid:11)

—

—

—

33

2

1

60

53

(cid:10)(cid:22)(cid:24)(cid:18)(cid:11)

380

36

9

—

—

—

(cid:10)(cid:23)(cid:21)(cid:11)

51

9

(cid:10)(cid:22)(cid:21)(cid:11)

1

1

(25)

(1,242)

(22)

(1,264)

(cid:10)(cid:22)(cid:23)(cid:26)(cid:11)

383

1,831

514

759

18

(cid:10)(cid:19)(cid:21)(cid:26)(cid:11)

(cid:10)(cid:23)(cid:21)(cid:11)

51

7

77

8

698

1,941

—

1

—

(21)

—

—

—

—

—

(cid:10)(cid:19)(cid:23)(cid:11)

3

—

—

(33)

(cid:10)(cid:22)(cid:23)(cid:26)(cid:11)

384

1,831

493

759

18

(cid:10)(cid:19)(cid:21)(cid:26)(cid:11)

(cid:10)(cid:23)(cid:21)(cid:11)

51

(cid:10)(cid:26)(cid:11)

80

8

698

1,908

(cid:10)(cid:67)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:6)(cid:19)(cid:21)(cid:22)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:2)(cid:81)(cid:72)(cid:2)(cid:87)(cid:80)(cid:84)(cid:71)(cid:67)(cid:78)(cid:75)(cid:92)(cid:71)(cid:70)(cid:2)(cid:79)(cid:67)(cid:84)(cid:77)(cid:15)(cid:86)(cid:81)(cid:15)(cid:79)(cid:67)(cid:84)(cid:77)(cid:71)(cid:86)(cid:2)(cid:80)(cid:71)(cid:86)(cid:2)(cid:73)(cid:67)(cid:75)(cid:80)(cid:85)(cid:2)(cid:81)(cid:80)(cid:2)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:71)(cid:85)(cid:86)(cid:2)(cid:84)(cid:67)(cid:86)(cid:71)(cid:2)(cid:85)(cid:89)(cid:67)(cid:82)(cid:85)(cid:16)

(cid:10)(cid:68)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:80)(cid:87)(cid:69)(cid:78)(cid:71)(cid:67)(cid:84)(cid:2)(cid:72)(cid:87)(cid:71)(cid:78)(cid:2)(cid:67)(cid:79)(cid:81)(cid:84)(cid:86)(cid:75)(cid:92)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:81)(cid:72)(cid:2)(cid:6)(cid:25)(cid:26)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:2)(cid:75)(cid:80)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:54)(cid:71)(cid:90)(cid:67)(cid:85)(cid:2)(cid:85)(cid:71)(cid:73)(cid:79)(cid:71)(cid:80)(cid:86)(cid:16)

(cid:10)(cid:69)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:79)(cid:67)(cid:86)(cid:71)(cid:84)(cid:75)(cid:67)(cid:78)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:85)(cid:87)(cid:82)(cid:82)(cid:78)(cid:75)(cid:71)(cid:85)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:81)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:75)(cid:80)(cid:69)(cid:84)(cid:71)(cid:79)(cid:71)(cid:80)(cid:86)(cid:67)(cid:78)(cid:2)(cid:69)(cid:81)(cid:85)(cid:86)(cid:85)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:86)(cid:81)(cid:2)(cid:81)(cid:87)(cid:84)(cid:2)(cid:37)(cid:49)(cid:56)(cid:43)(cid:38)(cid:15)(cid:19)(cid:27)(cid:2)(cid:84)(cid:71)(cid:85)(cid:82)(cid:81)(cid:80)(cid:85)(cid:71)(cid:16)

(cid:10)(cid:70)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:72)(cid:81)(cid:78)(cid:78)(cid:81)(cid:89)(cid:75)(cid:80)(cid:73)(cid:2)(cid:81)(cid:72)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:75)(cid:79)(cid:82)(cid:67)(cid:69)(cid:86)(cid:85)(cid:14)(cid:2)(cid:89)(cid:74)(cid:75)(cid:69)(cid:74)(cid:2)(cid:89)(cid:71)(cid:2)(cid:68)(cid:71)(cid:78)(cid:75)(cid:71)(cid:88)(cid:71)(cid:2)(cid:67)(cid:84)(cid:71)(cid:2)(cid:80)(cid:81)(cid:86)(cid:2)(cid:84)(cid:71)(cid:387)(cid:71)(cid:69)(cid:86)(cid:75)(cid:88)(cid:71)(cid:2)(cid:81)(cid:72)(cid:2)(cid:81)(cid:87)(cid:84)(cid:2)(cid:81)(cid:82)(cid:71)(cid:84)(cid:67)(cid:86)(cid:75)(cid:80)(cid:73)(cid:2)(cid:82)(cid:71)(cid:84)(cid:72)(cid:81)(cid:84)(cid:79)(cid:67)(cid:80)(cid:69)(cid:71)(cid:28)(cid:2)(cid:67)(cid:78)(cid:78)(cid:81)(cid:69)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:81)(cid:72)(cid:2)(cid:39)(cid:52)(cid:37)(cid:49)(cid:54)(cid:2)(cid:70)(cid:71)(cid:72)(cid:67)(cid:87)(cid:78)(cid:86)(cid:2)(cid:87)(cid:82)(cid:78)(cid:75)(cid:72)(cid:86)(cid:2)(cid:69)(cid:74)(cid:67)(cid:84)(cid:73)(cid:71)(cid:85)(cid:2)(cid:89)(cid:74)(cid:75)(cid:69)(cid:74)(cid:2)(cid:67)(cid:84)(cid:71)(cid:2)
(cid:71)(cid:90)(cid:82)(cid:71)(cid:69)(cid:86)(cid:71)(cid:70)(cid:2)(cid:86)(cid:81)(cid:2)(cid:68)(cid:71)(cid:2)(cid:82)(cid:67)(cid:75)(cid:70)(cid:2)(cid:81)(cid:88)(cid:71)(cid:84)(cid:2)(cid:79)(cid:81)(cid:84)(cid:71)(cid:2)(cid:86)(cid:74)(cid:67)(cid:80)(cid:2)(cid:27)(cid:18)(cid:2)(cid:91)(cid:71)(cid:67)(cid:84)(cid:85)(cid:2)(cid:87)(cid:80)(cid:70)(cid:71)(cid:84)(cid:2)(cid:69)(cid:87)(cid:84)(cid:84)(cid:71)(cid:80)(cid:86)(cid:2)(cid:82)(cid:84)(cid:81)(cid:86)(cid:81)(cid:69)(cid:81)(cid:78)(cid:85)(cid:29)(cid:2)(cid:67)(cid:69)(cid:69)(cid:84)(cid:87)(cid:67)(cid:78)(cid:2)(cid:81)(cid:72)(cid:2)(cid:45)(cid:81)(cid:69)(cid:74)(cid:2)(cid:71)(cid:67)(cid:84)(cid:80)(cid:15)(cid:81)(cid:87)(cid:86)(cid:2)(cid:67)(cid:79)(cid:81)(cid:87)(cid:80)(cid:86)(cid:85)(cid:2)(cid:86)(cid:74)(cid:67)(cid:86)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:37)(cid:81)(cid:79)(cid:82)(cid:67)(cid:80)(cid:91)(cid:2)(cid:89)(cid:75)(cid:78)(cid:78)(cid:2)(cid:82)(cid:67)(cid:91)(cid:2)(cid:68)(cid:91)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:71)(cid:80)(cid:70)(cid:2)(cid:81)(cid:72)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:85)(cid:71)(cid:69)(cid:81)(cid:80)(cid:70)(cid:2)(cid:83)(cid:87)(cid:67)(cid:84)(cid:86)(cid:71)(cid:84)(cid:2)(cid:81)(cid:72)(cid:2)(cid:20)(cid:18)(cid:20)(cid:20)(cid:29)(cid:2)(cid:72)(cid:87)(cid:86)(cid:87)(cid:84)(cid:71)(cid:2)
(cid:68)(cid:75)(cid:78)(cid:78)(cid:2)(cid:69)(cid:84)(cid:71)(cid:70)(cid:75)(cid:86)(cid:85)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:86)(cid:81)(cid:2)(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:10)(cid:67)(cid:85)(cid:2)(cid:72)(cid:87)(cid:84)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:70)(cid:71)(cid:85)(cid:69)(cid:84)(cid:75)(cid:68)(cid:71)(cid:70)(cid:2)(cid:68)(cid:71)(cid:78)(cid:81)(cid:89)(cid:11)(cid:29)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:78)(cid:71)(cid:73)(cid:67)(cid:78)(cid:2)(cid:72)(cid:71)(cid:71)(cid:85)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:81)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:69)(cid:81)(cid:85)(cid:86)(cid:85)(cid:16)(cid:2)(cid:54)(cid:74)(cid:71)(cid:2)(cid:67)(cid:70)(cid:76)(cid:87)(cid:85)(cid:86)(cid:79)(cid:71)(cid:80)(cid:86)(cid:2)(cid:72)(cid:81)(cid:84)(cid:2)(cid:72)(cid:87)(cid:86)(cid:87)(cid:84)(cid:71)(cid:2)(cid:68)(cid:75)(cid:78)(cid:78)(cid:2)(cid:69)(cid:84)(cid:71)(cid:70)(cid:75)(cid:86)(cid:85)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:85)(cid:2)(cid:86)(cid:81)(cid:2)(cid:78)(cid:67)(cid:84)(cid:73)(cid:71)(cid:2)
(cid:69)(cid:81)(cid:79)(cid:79)(cid:71)(cid:84)(cid:69)(cid:75)(cid:67)(cid:78)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:75)(cid:80)(cid:70)(cid:87)(cid:85)(cid:86)(cid:84)(cid:75)(cid:67)(cid:78)(cid:2)(cid:69)(cid:87)(cid:85)(cid:86)(cid:81)(cid:79)(cid:71)(cid:84)(cid:85)(cid:2)(cid:86)(cid:74)(cid:67)(cid:86)(cid:2)(cid:69)(cid:87)(cid:84)(cid:86)(cid:67)(cid:75)(cid:78)(cid:71)(cid:70)(cid:2)(cid:86)(cid:74)(cid:71)(cid:75)(cid:84)(cid:2)(cid:87)(cid:85)(cid:67)(cid:73)(cid:71)(cid:2)(cid:70)(cid:87)(cid:84)(cid:75)(cid:80)(cid:73)(cid:2)(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:89)(cid:75)(cid:78)(cid:78)(cid:2)(cid:84)(cid:71)(cid:88)(cid:71)(cid:84)(cid:85)(cid:71)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:75)(cid:79)(cid:82)(cid:67)(cid:69)(cid:86)(cid:2)(cid:35)(cid:70)(cid:76)(cid:87)(cid:85)(cid:86)(cid:71)(cid:70)(cid:2)(cid:39)(cid:36)(cid:43)(cid:54)(cid:38)(cid:35)(cid:2)(cid:75)(cid:80)(cid:2)(cid:72)(cid:87)(cid:86)(cid:87)(cid:84)(cid:71)(cid:2)(cid:82)(cid:71)(cid:84)(cid:75)(cid:81)(cid:70)(cid:85)(cid:2)(cid:67)(cid:85)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:69)(cid:84)(cid:71)(cid:70)(cid:75)(cid:86)(cid:85)(cid:2)(cid:67)(cid:84)(cid:71)(cid:2)(cid:67)(cid:82)(cid:82)(cid:78)(cid:75)(cid:71)(cid:70)(cid:2)(cid:86)(cid:81)
(cid:69)(cid:87)(cid:85)(cid:86)(cid:81)(cid:79)(cid:71)(cid:84)(cid:2)(cid:68)(cid:75)(cid:78)(cid:78)(cid:85)(cid:16)(cid:2)(cid:57)(cid:71)(cid:2)(cid:71)(cid:85)(cid:86)(cid:75)(cid:79)(cid:67)(cid:86)(cid:71)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:67)(cid:79)(cid:81)(cid:87)(cid:80)(cid:86)(cid:85)(cid:2)(cid:86)(cid:81)(cid:2)(cid:68)(cid:71)(cid:2)(cid:67)(cid:82)(cid:82)(cid:78)(cid:75)(cid:71)(cid:70)(cid:2)(cid:75)(cid:80)(cid:2)(cid:72)(cid:87)(cid:86)(cid:87)(cid:84)(cid:71)(cid:2)(cid:82)(cid:71)(cid:84)(cid:75)(cid:81)(cid:70)(cid:85)(cid:2)(cid:67)(cid:84)(cid:71)(cid:2)(cid:20)(cid:18)(cid:20)(cid:20)(cid:2)(cid:10)(cid:67)(cid:82)(cid:82)(cid:84)(cid:81)(cid:90)(cid:75)(cid:79)(cid:67)(cid:86)(cid:71)(cid:78)(cid:91)(cid:2)(cid:6)(cid:19)(cid:23)(cid:18)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:11)(cid:14)(cid:2)(cid:20)(cid:18)(cid:20)(cid:21)(cid:2)(cid:10)(cid:67)(cid:82)(cid:82)(cid:84)(cid:81)(cid:90)(cid:75)(cid:79)(cid:67)(cid:86)(cid:71)(cid:78)(cid:91)(cid:2)(cid:6)(cid:24)(cid:25)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:11)(cid:14)(cid:2)(cid:20)(cid:18)(cid:20)(cid:22)(cid:2)(cid:10)(cid:67)(cid:82)(cid:82)(cid:84)(cid:81)(cid:90)(cid:75)(cid:79)(cid:67)(cid:86)(cid:71)(cid:78)(cid:91)(cid:2)(cid:6)(cid:19)(cid:19)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:11)(cid:2)
(cid:67)(cid:80)(cid:70)(cid:2)(cid:20)(cid:18)(cid:20)(cid:23)(cid:2)(cid:10)(cid:67)(cid:82)(cid:82)(cid:84)(cid:81)(cid:90)(cid:75)(cid:79)(cid:67)(cid:86)(cid:71)(cid:78)(cid:91)(cid:2)(cid:6)(cid:22)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:11)(cid:16)(cid:2)(cid:54)(cid:74)(cid:71)(cid:2)(cid:37)(cid:81)(cid:79)(cid:82)(cid:67)(cid:80)(cid:91)(cid:2)(cid:68)(cid:71)(cid:78)(cid:75)(cid:71)(cid:88)(cid:71)(cid:85)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:75)(cid:80)(cid:69)(cid:78)(cid:87)(cid:85)(cid:75)(cid:81)(cid:80)(cid:2)(cid:81)(cid:72)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:68)(cid:75)(cid:78)(cid:78)(cid:2)(cid:69)(cid:84)(cid:71)(cid:70)(cid:75)(cid:86)(cid:85)(cid:2)(cid:67)(cid:85)(cid:2)(cid:67)(cid:2)(cid:84)(cid:71)(cid:70)(cid:87)(cid:69)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:86)(cid:81)(cid:2)(cid:35)(cid:70)(cid:76)(cid:87)(cid:85)(cid:86)(cid:71)(cid:70)(cid:2)(cid:39)(cid:36)(cid:43)(cid:54)(cid:38)(cid:35)(cid:2)(cid:75)(cid:80)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:91)(cid:71)(cid:67)(cid:84)(cid:85)(cid:2)(cid:75)(cid:80)(cid:2)(cid:89)(cid:74)(cid:75)(cid:69)(cid:74)(cid:2)(cid:85)(cid:87)(cid:69)(cid:74)(cid:2)(cid:68)(cid:75)(cid:78)(cid:78)(cid:2)(cid:69)(cid:84)(cid:71)(cid:70)(cid:75)(cid:86)(cid:85)(cid:2)(cid:67)(cid:84)(cid:71)(cid:2)(cid:67)(cid:82)(cid:82)(cid:78)(cid:75)(cid:71)(cid:70)(cid:2)(cid:79)(cid:81)(cid:84)(cid:71)(cid:2)
(cid:67)(cid:69)(cid:69)(cid:87)(cid:84)(cid:67)(cid:86)(cid:71)(cid:78)(cid:91)(cid:2)(cid:84)(cid:71)(cid:387)(cid:71)(cid:69)(cid:86)(cid:85)(cid:2)(cid:75)(cid:86)(cid:85)(cid:2)(cid:81)(cid:82)(cid:71)(cid:84)(cid:67)(cid:86)(cid:75)(cid:80)(cid:73)(cid:2)(cid:82)(cid:71)(cid:84)(cid:72)(cid:81)(cid:84)(cid:79)(cid:67)(cid:80)(cid:69)(cid:71)(cid:16)

VISTRA 2021 ANNUAL REPORT

8

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, 2021

— OR —

RR
☐ TRANSIT

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

For the transition period from __ to __

Commission File Number 001-38086
Vistra 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
75039
(Address of principal executive offices) (Zip Code)

Irving, Texas

(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

Trading Symbol(s)
VST
VST.WS.A

Name of Each Exchange on Which Registered
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 RuleRR

405 of the Securities Act. Yes ☒ No ☐

Indicated by check mark if the registrant is not required to fileff

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 ☐

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 ☐

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.

ff

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer

ff

☐ 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. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its
internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public
accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of June 30, 2021, the aggregate market value of the Vistra Corp. common stock held by non-affiliates of the registrant was $8,921,038,713
based on the closing sale price as reported on the New York Stock Exchange.

As of February 22, 2022, there were 448,803,986 shares of common stock, par value $0.01, outstanding of Vistra Corp.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the registrant's 2022 annual meeting of stockholders are incorporated in Part III of this annual report on
Form 10-K.

TABLE OF CONTENTS

PAGE

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 9C.

Item 10.
Item 11.
Item 12.

Item 13.

Item 14.

Item 15.
Item 16.
Signatures

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
[RESERVED]
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATRR IONS
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
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT
INSPECTION

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 ACCOUNTANT FEES AND SERVICES

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY

PART IV.

ii

1
19
46
46
48
48

49

50
50

80
86
164

164
166
166

167
167
167

167

167

168
183
184

Vistra Corp.'s (Vistra) annual reports, quarterly reports, current reports and any amendments to those reports are made available to the public,
free of charge, on the Vistra website at http://www.vistracorp.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 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's website. The information on Vistra'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 forff

securities law purposes.

This annual report on Form 10-K and other Securities and Exchange Commission filings of Vistra and its subsidiaries occasionally make
references to Vistra (or "we," "our," "us" or "the Company"), Luminant, TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services,
Homefield Energy, TriEagle Energy, Public Power or U.S. Gas & Electric, 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, the Vistra 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.

i

When the folff

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

GLOSSARY

2020 Form 10-K

Ambit or Ambit Energy

ARO

CAA

CAISO

Vistra's annual report on Form 10-K for the year ended December 31, 2020, filed with the
SEC on February
Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context

26, 2021

rr

asset retirement and mining reclamation obligation

Clean Air Act

The California Independent System Operator

CARES Act

Coronavirus Aid, Relief, and Economic Security Act

CCGT

CCR

CFTC

Chapter 11 Cases

CME
CO2
CPUC

Crius

CT

Dynegy

Dynegy Energy Services

EBITDA

Effecff

tive Date

Emergence

ESG

EPA

ERCOT

ESS

Exchange Act

FERC

Fitch

FTC

GAAP

GHG

GWh

combined cycle gas turbine

coal combustion residuals

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 (Petition Date) by Energy Future Holdings
Corp.r
(EFH Corp.) and the majoa rity of its direct and indirect subsidiaries, including Energy
Future Intermediate Holding Company LLC, Energy Future Competitive Holdings
Company LLC and TCEH but excluding Oncor Electric Delivery Holdings Company LLC
and its direct and indirect subsidiaries (Debtors). On the Effective Date, subsidiaries of
TCEH that were Debtors in the Chapter 11 Cases (TCEH Debtors), along with certain other
Debtors that became subsidiaries of Vistra on that date (Contributed EFH Debtors)
emerged fromff

the Chapter 11 Cases.

Chicago Mercantile Exchange

carbon dioxide

ff
Californi

a Public Utilities Commission

Crius Energy Trust and/or its subsidiaries, depending on context

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

Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/bdd /a
Dynegy, Better Buy Energy, Brighten Energy, Honor Energy and True Fit Energy),
indirect, wholly owned subsidiaries of Vistra, 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

October 3, 2016, the date the TCEH Debtors and the Contributed EFH Debtors completed
their reorganization under the Bankruptcy Code and emerged fromff
emergence of the TCEH Debtors and the Contributed EFH Debtors from the Chapter 11
Cases as subsidiaries of a newly formed company, Vistra, on the Effective Date
environmental, social and governance

the Chapter 11 Cases

U.S. Environmental Protection Agency

Electric Reliabila

ity Council of Texas, Inc.

energy storage system

Securities Exchange Act of 1934, as amended
U.S. Federal Energy Regulatory Commission

Fitch Ratings Inc. (a credit rating agency)

Federal Trade Commission

generally accepted accounting principles

greenhouse gas

gigawatt-hours

Homefield Energy

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

ii

ICE

IEPA

IPCB

IRC

IRS

ISO

ISO-NE

kW

LIBOR

load

LTSA

Luminant

market heat rate

Merger

Merger Agreement

Merger Date

MISO

MMBtu

Moody's

MSHA

MW

MWh

NELP

NELP Transaction

NERC

NJEA
NOX
NRC

NYISO

NYMEX

NYSE

Oncor

OPEB

Parent

PJM

Intercontinental Exchange

Illinois Environmental Protection Agency

Illinois Pollution Control Board

Internal Revenue Code of 1986, as amended

U.S. Internal Revenue Service

independent system operator

ISO New England Inc.

kilowatt

London Interbank Offered Rate, an interest rate at which banks can borrow funds, in
marketable size, fromff
demand for electricity

other banks in the London interbank market

long-term service agreements for plant maintenance

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

source to electricity. Market
Heat rate is a measure of the efficiency of converting a fuel
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 naturat

l gas.

ff

t

t

the merger of Dynegy with and into Vistra, with Vistra as the surviving corporation
the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra
and Dynegy
April 9, 2018, the date Vistra 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

Northeast Energy, LP, a joint venturet
between Dynegy Northeast Generation GP, Inc. and
Dynegy Northeast Associates LP, Inc., both indirect subsidiaries of Vistra, and certain
subsidiaries of NextEra Energy, Inc. Prior to the NELP Transaction, NELP indirectly
owned Bellingham NEA facility and the Sayreville facff

ility.

a transaction among Dynegy Northeast Generation GP, Inc., Dynegy Northeast Associates
LP, Inc. and certain subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries
of Vistra redeemed their ownership interest in NELP partnership in exchange for 100%
ownership interest in NJEA, the entity which owns the Sayreville facility

North American Electric Reliabila

ity Corporation

North Jersey Energy Associates, A Limited Partnership

nitrogen oxide

U.S. Nuclear Regulatory Commission

New York Independent System Operator, Inc.

the New York Mercantile Exchange, a commodity derivatives exchange

New York Stock Exchange

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

postretirement employee benefits other than pensions

Vistra Corp.

PJM Interconnection, LLC

iii

Plan of Reorganization

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

PrefCo

Vistra Preferred Inc.

PrefCo Preferred Stock Sale

Preferred Stock

Public Power

as part of the Spin-Off, tff he 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
Vistra's Series A Preferred Stock and Series B Preferred Stock

Public Power, LLC (d/b/a Public Power), an indirect, wholly owned subsidiary of Vistra, a
REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale
of electricity to residential and business customers

PUCT

PURARR

REP

RCT

RTO
S&P

SEC

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
gas exploration and production,
activity in Texas, and has jurisdiction over oil and natural
permitting and inspecting intrastate pipelines, and overseeing natural
gas utility rates and
compliance
regional transmission organization

t

t

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

U.S. Securities and Exchange Commission

Securities Act

Securities Act of 1933, as amended

Series A Preferrff

ed Stock

Series B Preferred Stock

SG&A
SO2
Spin-Off

ST

Tax Matters Agreement

TCJA

TCEH or Predecessor

Vistra's 8.0% Series A Fixed Rate Reset Cumulative Redeemable Perpet
t
ual
Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Vistra's 7.0% Series B Fixed Rate Reset Cumulative Redeemable Perpet
t
ual
Stock, $0.01 par value, with a liquidation preference of $1,000 per share
selling, general and administrative

r

r

Preferred

Preferred

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
steam turbine

Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., Energy
Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC
The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December
2017, which significantly changed the tax laws appli
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 whose majoa r subsidiaries included Luminant and
TXU Energy

to business entities

cablea

a

TCEH Debtors

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

TCEQ

TRA

TRE

TriEagle Energy

TWh

TXU Energy

Texas Commission on Environmental Quality

ights) to receive payments
Tax Receivables Agreement, containing certain rights (TRA RRR
from Vistra related to certain tax benefits, including benefits realized as a result of certain
transactions entered into at Emergence (see Note 8 to the Financial Statements)

Texas Reliability Entity, Inc., an independent organization that develops reliabia lity
standards for the ERCOT region and monitors and enforces compliance with NERC
standards and monitors compliance with ERCOT protocols

TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy,
Energy Rewards, Power House Energy and Viridian Energy), an indirect, wholly owned
subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail
sale of electricity to residential and business customers

terawatt-hours

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

iv

U.S.

U.S. Gas & Electric

Value Based Brands

Vistra

Vistra Intermediate

Vistra Operations

United States of America

U.S. Gas and Electric, Inc. (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an indirect,
wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and
MISO that is engaged in the retail sale of electricity to residential and business customers

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

Vistra 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 fromff
Chapter 11 and became subsidiaries of Vistra Energy Corp. Effective July 2,
2020, Vistra Energy Corp. changed its name to Vistra Corp.

Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra

Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the
issuer of certain series of notes (see Note 11 to the Financial Statements) and borrower
under the Vistra Operations Credit Facilities

Vistra Operations Credit
Facilities
Vistra Zero

Vistra Operations senior secured financing facilities (see Note 11 to the Financial
Statements)
Vistra Zero LLC

v

[THIS PAGE INTENTIONALLY LEFT BLANK]

Item 1. BUSINESS

PART I

Refereff

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

context. See Glossary for defined terms.

Business

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets
throughout the U.S. Through our subsidiaries, we are engaged in competitive energy activities including electricity generation,
gas to end users.
wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural
Vistra Energy Corp. to
We incorporated under Delaware law in 2016. Effective July 2, 2020, we changed our name fromff
Vistra Corp. to distinguish from companies that are involved in exploring for, producing, refining, or transporting fossil fuel
s
(many of which use "energy" in their names) and to better reflect our integrated business model, which combines a retail
on serving its customers with new and innovative products and services and an
electricity and natural
electric power generation business leading the clean power transition through our Vistra Zero portfolio while powering the
communities we serve with safe, reliable and affordablea

gas business focused

power.

ff

ff

t

t

We serve approximately 4.3 million customers and operate in 20 states and the District of Columbia. Our generation fleet
totals approxi
gas, nuclear, coal, solar and battery energy
a
storage facilities.

mately 38,700 MW of generation capac

ity with a portfolio of natural

a

t

Vistra has six reportablea
t Discussion below and Note 20 to the Financial Statements for furff
MarMM kerr
including an update of our reportable segments in the third quarter of 2020.

segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See
ther information concerning our reportable segments,

Business Strate

gye

tt

Vistra is a leader in the clean power transition. With a strong zero-carbon generation portfolio and a deliberate and
and value for all stakeholders. Our

responsible strategy to decarbonize, the company is focused on delivering healthy returns
business strategy is focused on the following areas:

t

1

•

•

•

ation. Vistra's strategy is to responsibly and reliablya

and resilient company well positioned to generate stablea

grow our business through economically
Growth and transforms
, and energy storage assets that assist in reducing our carbon footprint and
attractive investments in retail, renewablea
create a more sustainablea
long-term value for all of our
stakeholders. Since 2010, Vistra has retired more than 12,000 MW of coal and gas power plants resulting in a 45%
reduction of greenhouse gas (GHG emissions), a 45% reduction in carbon dioxide (CO2) emissions, a 55% reduction
in nitrogen oxide (NOX) emissions, and a 75% reduction in sulfur dioxide (SO2) emissions through year-end 2020,
compared to a 2010 baseline. Now, we are transforming our generation portfolio through investments in zero-carbon
resources and new carbon-reducing technologies, targeting net-zero carbon emissions by 2050. By year-end 2026,
our Vistra Zero portfolio is expected to grow to 7,300 MW of zero-carbon generation, including solar, energy storage
and our Comanche Peak nuclear power plant. Additionally, we have announced the retirement of approximately
sible sites to solar and energy storage
7,500 MW of coal-fueled power plants by 2027, with plans to repurpose feaff
to the
developments. Repurposed sites provide a strategic advantage in the development of greener power dued
interconnection infrastructuret
they allow us to continue
already available, but additionally, and importantly,
supporting the local communities and our employees in those areas. We believe our diversified asset mix will
support the reliability of the electric system while providing customers with cost-effeff ctive energy that meets their
lities of
sustainable preferences throughout the clean power transition. Our growth strategy leverages our core capabi
multi-channel retail marketing in large and competitive markets, operating large-scale, environmentally sensitive, and
technologies, fuel logistics and management, commodity risk management, cost
diverse assets across a variety of fuel
ff
control, and energy infrastructuret
investing. To advance our sustainability and energy transition initiatives, in
December 2021, we adopted our Green Finance Framework, pursuant to which we issued $1.0 billion of Series B
Preferred Stock to finance or refinance, in whole or in part, new or existing eligible green projects. We intend to
opportunistically evaluate the acquisition and development of high-quality generation and storage assets and power-
related businesses,
that
complement our core capabi
ncial and sustainability goals. We pride
ourselves on our deliberate and responsible approach to grow and transform, considering impacts on all stakeholders.
We make disciplined investments that are consistent with our focus on maintaining both a strong balance sheet and
strong liquidity profile and our commitment to ensuring grid reliabila
power, and pursuit of a just
transition away from carbon-emitting generation assets for the communities in which we operate and serve. As a
l process, the growth opportunities we pursue must
a
result, consistent with our disciplined capita
have compelling economic value and align with or enhance our purpose and core principles.

including renewable energy and battery storage assets as well as retail businesses,

lities and align with our operational, finaff

al allocation approva

ity, affordablea

a

a

t

capita

In addition to our dedicated approa

Disciplined capital allocation. Vistra takes a disciplined approach to capital allocation in support of our commitment
al allocation decisions that we believe will lead to
to maintain a strong balance sheet. We thoughtfully make capita
al to our stockholders through quarterly dividends and
attractive cash returns on investment, including returning
our share repurchase program as reflected in our current plans to returnt
al to common
up to $7.5 billion in capita
o $3 billion in debt (exclusive of potential limited recourse project financing) through
shareholders and reduce up tu
value to all stakeholders, we invest prudently in the
2026.
maintenance of our existing assets and potential growth acquisitions. 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 needed to make prudent capita
al investment decisions. We believe in cost discipline and
strong commercial management of our assets and commodity positions to deliver long-term value to our stakeholders,
ity of our facilities, all while accelerating growth in our Vistra Zero portfolio
to maintain the safety a
pipeline with cost-efficient capita
al and investment in new technologies when economic, including solar assets and
energy storage systems, resulting in a continued modernization of Vistra's generation fleet.

t
ch to returning

nd reliabila

a

t

e

business model. Our integrated business model is an important component of our business strategy. This
Integrated
d by our diversified portfolio. This key factor
element of our business provides long-term sustainable solutions enablea
and efficient mining, diversified generation
distinguishes us from our electricity competitors by pairing our reliablea
fleet and wholesale commodity risk management capabi
lities with our retail platform. Coupling retail with
generation is a core competitive advantage that reduces the effects of commodity price movements and contributes to
stable earnings and predictable cash flow,
ture of the strategy as Vistra responsibly grows its renewables
portfolio and winds down its carbon-em

a crucial feaff

itting assets.

a

ff

r

2

•

•

•

•

t

and affordablea

Superior customer service. Through our retail brands, including TXU Energy, Ambit Energy, Value Based Brands,
Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric, we serve the
gas needs of end-use residential, small business, commercial and industrial electricity
retail electricity and natural
In addition to benefitting from our integrated business
customers through multiple sales and marketing channels.
model, we leverage our brands, our commitment to a safe, reliablea
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 solutions from our competitors. We strive to be at the
of innovation with new environmentally-conscious and sustainable-focused product offerings and customer
ff
forefront
experiences to reinforce our value proposition. We maintain a focuff
s on solutions that provide our customers with
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 renewabla e energy credit program
and a diverse set of solar options. Our focus on superior customer service guides our efforts in acquiring new
residential and commercial customers, serving and retaining existing customers, and maintaining valuable sales
channels forff
our electricity generation resources. We believe our dependable customer service, innovative products
and trusted brands will result in high residential customer retention rates, particularly in Texas where our TXU
Energy brand has maintained its residential customers in a highly competitive retail market.

o

Excellence in operati
ons while maintaining an effiff cient cost structure. We believe delivering long-term stakeholder
value is increased as a result of making disciplined investments that enable our generation facilities to operate not
only effectively and efficiently, but also safely, reliablya
and in an environmentally compliant manner as we lead in
the clean power transition through the acceleration of our renewables portfolio. We believe that an ongoing focus on
operational excellence and safety i
s 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 safetyff
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 and is instrumental in our
long-term value proposition.

t

d hedging and commercial management. Our commercial team is focuse

Integrate
d on effectively and efficiently
e
managing risk, through opportunistic hedging, and optimizing our assets and business positions. We proactively
manage our exposure to wholesale electricity prices and fuel costs in markets in which we operate, on an integrated
ncial contracts,
basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter finaff
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. We actively hedge near-term cash flows 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 attractive liquidity profile, will
provide long-term advantages through cycles of higher and lower commodity prices.

ff

s

ity att

nd ESG initiatives.

Corporate responsibil
It is our purpose to light up people's lives and power a better way
forward. We strive to be a good corporate citizen by investing in our employees, putting customers and suppliers
first, and improving communities where we live, work and serve as we accelerate toward a clean energy future.
Vistra and its employees are actively engaged in programs intended to support our customers and strengthen the
communities in which we conduct operations. Our foremost giving initiatives are through the United Way, TXU
Energy Aid and Ambit Cares campaigns. TXU Energy Aid serves as an integral resource for social service agencies
that assist those in need across Texas pay their electricity bills. Ambit Cares partners with Feeding America® to
assist those in need across the U.S. by fighting hunger through a network of food banks. Beyond these giving
initiatives, Vistra embeds ESG and considers all stakeholders – customers, suppliers, local communities, employees,
contractors, investors and the environment, among others – into all of our decisions, processes and activities. The
Board has ultimate oversight of all our ESG initiatives and ensures these considerations are embedded at every level
of our company. We know that prioritizing our stakeholders leads to higher customer satisfaction, more community
involvement and support, and committed employees and suppliers, which in turn,
leads to a more sustainablea
company. Our ESG initiatives complement our business strategy and strengthen our resiliency. For instance, our
investment in and growth of Vistra Zero supports our long-term goal to achieve net-zero carbon emissions by 2050.
We stay informed of evolving ESG standards and remain committed to provide specific and measurablea
ESG goals
and initiatives in a transparent manner.

t

3

Recent Developme

o

nts

Dividendd d Declarations — In February 2022, the Board declared a quarterly dividend of $0.17 per share of common stock
that will be paid in March 2022 and a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in
April 2022.

Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which
ncial instruments to fund new or existing projects that support renewabla e energy and energy
allows us to issue green finaff
efficiency with alignment to our ESG initiatives. See below and Note 14 to the Financial Statements for more information
concerning the Series B Preferre

d Stock, which was issued in December 2021 under the Green Finance Framework.

ff

ff

d StocS

Series A Preferre

k OffeO ring — On October 15, 2021, we issued 1,000,000 shares of Series A Preferred Stock in a
private offering (Series A Offering). The net proceeds of the Series A Offering were approximately $990 million, after
deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series A Offering to
repurchase shares of our outstanding common stock under the Share Repurchase Program. See Note 14 to the Financial
Statements for more information concerning the Series A Preferred Stock and our Share Repurchase Program.

ff

d StocS

Series B Preferre

k OffeO ring — On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a
private offering (Series B Offering) under our Green Finance Framework. The net proceeds of the Series B Offering were
approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the proceeds
from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments. See
Note 14 to the Financial Statements forff more information concerning the Series B Preferred Stock.

Commodity-Linked Revolving Credit Facility — On February 4, 2022, Vistra Operations entered into a credit agreement
by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and
Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides forff
a $1.0 billion senior secured
commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity
provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which
al and
Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capita
general corporate purposes. See Note 11 to the Financial Statements for more information concerning the Commodity-Linked
Facility.

Market Discussion

The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v)

Sunset and (vi) Asset Closure. The folff

lowing is a summary of our segments:

•

•

•

•

•

•

t

gas to residential, commercial and

The Retail segment represents Vistra's retail sales of electricity and natural
industrial customers.
The Texas segment represents Vistra's electricity generation operations in ERCOT, other than assets that are now part
of the Sunset or Asset Closure segments, respectively.
The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S.
electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes
operations in PJM, ISO-NE and NYISO.
The West segment represents Vistra's electricity generation operations in CAISO. As reflected by the Moss Landing
and Oakland ESS projects (see Note 3 to the Financial Statements), the Company expects to expand its operations in
the West segment.
The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT,
PJM and MISO segments. Given recent and expected future retirements of certain power plants, management
ates between operating plants with defined retirement plans
believes it is important to have a segment which differenti
and operating plants without defined retirement plans.
The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines.

ff

See Note 20 to the Financial Statements forff

further information concerning reportable segments.

4

Independent System Operator

O

((
s (rr
ISOs)

and Regioe

nal Transmissi

ii

on Organizati

ii

ons (RTOs)

both maximum utilization and reliablea

Separately, ISOs/RTOs 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 forff
ISOs/RTOs
administer energy and ancillary service markets in the short term, which usually consists of day-ahead and real-time markets.
Several ISOs/RTOs also ensure long-term planning reserves through monthly, semiannual, annual and multi-year capacity
markets. The ISOs/RTOs 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 ISOs/RTOs often have different
geographic
overlap between NERC regions and ISOs/RTOs, their respective
a
roles and responsibilities do not generally overlap.a

and efficient operation of the transmission system.

footprints, and while there may be geographic

a

ff

t

In ISO/RTO regions with centrally dispatched market structures

(e.g., ERCOT, PJM, ISO-NE, NYISO, MISO, and
CAISO), all generators selling into the centralized market receive the same price forff
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
prices respective to other zones
given location. Different zones or locations within the same ISO/RTO may produce different
within the same ISO/RTO due to transmission losses and congestion. For example, a less efficient and/or less economical
gas-fueled unit may be needed in some hours to meet demand. If this unit's production is required to meet demand on
natural
t
the margin, its offer price will set the market clearing price that will be paid forff
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. Generators will receive the location-based
marginal price for their output.

ff

t

Retail MarkMM etkk stt

The Retail segment is engaged in retail sales of electricity, natural

mately 4.3 million
customers. Substantially all of these activities are conducted by TXU Energy, Ambit Energy, Value Based Brands, Dynegy
Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 U.S. states and the
District of Columbia.

gas and related services to approxi

a

t

The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 2.4 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, strong brands, innovative products and services and excellent customer
service. As of December 31, 2021, we provided electricity to approximately 30% of the residential customers in ERCOT and
for approximately 15% of business customers' demand. We believe that we have differentiated ourselves by providing a
distinctive customer experience predicated on delivering reliablea
and innovative power products and solutions to our customers,
which give our customers choice, convenience and control over how and when they use electricity and related services. Our
retail business also offers a comprehensive suite of green products and services, including 100% wind and solar options, as well
as thermostats, dashboards and other programs designed to encourage reduced consumptim on and increased energy efficiency.

Our integrated power generation and wholesale operation allows us to efficiently obtain the electricity needed to serve our
customers at the lowest cost. The integrated model enablea
s us to 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 help 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) and achieve 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 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.

t

Outside of ERCOT, we also serve residential, municipal, commercial and industrial customers substantially through our
Homefield Energy, Dynegy Energy Services, Public Power, U.S. Gas & Electric and Ambit Energy retail businesses, through
which we provide retail electricity, natural
gas and related services to approximately 1.9 million customers in 18 states and the
District of Columbia.

t

5

ee
Texas

Segment

Our Texas segment is comprised of 18 power generation facilities totaling 17,623 MW of generation capac

a

ity in ERCOT.

We also operate a 10 MW battery ESS at our Upton 2 solar facility.

ISO/RTO
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT

Technology
CCGT
ST
CT or ST
Nuclear
Solar/Battery

Primary Fuel
Naturt al Gas
Coal

Naturat

l Gas

Nuclear
Renewable
Total Texas Segment

Number of Facilities
7
2
7
1
1
18

Net Capacity (MW)

7,838
3,850
3,455
2,300
180
17,623

We plan to develop up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas
with estimated commercial operation dates between first quarter of 2022 to fourth quarter of 2023. See Note 3 to the Financial
Statements for a summary orr

f our solar and battery energy storage projects.

ERCOT — ERCOT is an ISO that manages the flow of electricity from approximately 86,000 MW of summer peak

generation capaa

city to approximately 26 million Texas customers, representing approximately 90% of the state's electric load.

As an energy-only market, ERCOT's market design is distinct fromff

other competitive electricity markets in the U.S.
Other markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/
ity markets. In contrast, ERCOT's resource adequacy is predominately dependent on energy-market price signals. In
a
or capac
2014, ERCOT implemented the Operating Reserve Demand Curve (ORDC), pursuant to which wholesale electricity prices in
the real-time electricity market increase automatically as availablea
operating reserves decrease below defined threshold levels,
creating a price adder. The slope of the ORDC curve is determined through a mathematical loss of load probability calculation
In both March 2019 and March 2020, ERCOT implemented 0.25 standard
using forecasted reserves and historical data.
deviation shifts in the loss of load probability calculation and moved to using a single blended ORDC curve; these changes
resulted in a more rapid escalation in power prices as operating reserves falff
l below defined thresholds. Effective January 1,
2022, when operating reserves drop to 3,000 MW or less, the ORDC automatically adjud sts power prices to the established value
ERCOT also calculates the
of lost load (VOLL), which is set at $5,000/MWh which is equal to the high system-wide offer cap.a
If the peaker net
"peaker net margin" based on revenues a hypothetical unhedged peaking unit would collect in the market.
margin exceeds a certain threshold, the system-wide offer cap ia
f $2,000/MWh for
s reduced to the low system-wide offer cap oa
the remainder of the calendar year. The peaker net margin exceeded the threshold for the first time during Winter Storm Uri,
as in place for the balance of 2021. Historically, high demand due to elevated
and as a result the low system-wide offer cap wa
temperatures
in the winter months, combined with
underperformance of wind generation, has created the conditions during which the ORDC contributes meaningfully to power
prices. Extreme weather conditions can also lead to scarcity conditions regardless of season. Other than during periods of
"scarcity pricing," the price of power is typically set by natural
ilities (see Item 7. Management's
Discussion and Analysis

t
f Oo
of Financial Condition and Results ott

gas-fueled generation facff
peO rations – KeyKK Operational Risks

in the summer months or high demand due to reduced temperatures

and Challenges).

t

ll

t

ii

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, financial 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 physical
market in which electricity is dispatched and priced 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
In addition,
markets allow market participants to manage their risk profile by adjusting their participation in each market.
ERCOT uses ancillary services to maintain system reliabia lity, including regulation service, responsive reserve service and non-
voltage and frequency
spinning reserve service. Ancillary services are provided by generators to help maintain the stablea
requirements of the transmission system. Because ERCOT has one of the highest concentrations of wind and solar capac
ity
tuations in wholesale electricity supply due to
generation among U.S. markets, the ERCOT market is more susceptible to flucff
intermittent wind and solar production, making ERCOT more vulnerable to periods of generation scarcity. Beginning in July
2021, ERCOT has increased its ancillary s
ervice procurement volumes to maintain a more conservative level of operating
reserves.

a

rr

6

East Segment

Our East segment is comprised of 21 power generation facilities in 10 states totaling 12,093 MW of generating capac

a

ity in

PJM, ISO-NE and NYISO.

ISO/RTO
PJM
PJM
PJM
ISO-NE
NYISO

Technology
CCGT
CT
CT
CCGT
CCGT

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

Total East Segmen

t

Number of Facilities
8
4
2
6
1
1
2

Net Capacity (MW)

6,081
1,346
93
3,361
1,212
12,093

We plan to develop up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at
retired or to-be-retired plant sites in Illinois with estimated commercial operation dates for these facilities ranging from 2023 to
2025. See Note 3 to the Financial Statements for a summary of our solar and battery energy storage projects.

ity to
PJMJJ — PJM is an RTO that manages the flow of electricity from approximately 180,000 MW of generation capac
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.

a

ff

a
capac

Like ERCOT, PJM administers markets forff wholesale electricity and provides transmission planning for the region,
every generator and load point within
utilizing a locational marginal pricing (LMP) methodology which calculates a price forff
PJM. PJM operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services.
PJM also administers a forward
ity auction, the Reliability Pricing Model (RPM), which establishes a long-term market
for capac
ity. We have participated in RPM auctions for years up to and including PJM's planning year 2022-2023, which ends
a
May 31, 2023. Due to a FERC order issued in December 2021, PJM's RPM auction for planning year 2023-2024 will be
delayed and is expected to be run in the summer of 2022. We also enter into bilateral capacity transactions. PJM's Capacity
Performance (CP) ruler
under-performing units and
reward for over-performing units during shortage events. Full transition of the capacity market to CP rules occurred in planning
year 2020-2021. An independent market monitor continually monitors PJM markets to ensure a robust, competitive market and
to identify improper behavior by any entity.

s were designed to improve system reliabia lity and include penalties forff

ISO-NENN — ISO-NE is an ISO that manages the flow of electricity from approximately 31,000 MW of installed generation
mately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode
a
ity to approxi

a
capac
Island and Maine.

ISO-NE dispatches power plants to meet system energy and reliabila

ity needs and settles physical power deliveries at
LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through
real-time and day-ahead auctions. Energy prices vary among the participating states in ISO-NE and are largely influenced by
transmission constraints and fuel supply.
ity prices are determined
ff
through auctions. Performanc
ity 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.

ISO-NE offers a forward
e incentive rules have the potential to increase capac

ity market where capac

a
capac

a

a

ff

NYISOYY — NYISO is an ISO that manages the flow of electricity from approximately 39,000 MW of installed summer

generation capaa

city to approximately 20 million New York customers.

NYISO dispatches power plants to meet system energy and reliabila

ity needs and settles physical power deliveries at
LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through
real-time and day-ahead auctions. Energy prices vary among the regional zones in the NYISO and are largely influenced by
transmission constraints and fuel supply. NYISO offers a forward
ity prices are determined
ff
through auctions. Strip auctions occur one to two months prior to the commencement of a six-month seasonal planning period.
the balance of the seasonal planning period or the
Subsequent auctions provide an opportunity to sell excess capac
a
upcoming month. Due to the short-term naturet
ity auctions and a relatively liquid bilateral market
of the NYISO-operated capac
for NYISO capac
ility sells a significant portion of its capacity through bilateral transactions.
The balance is cleared through the seasonal and monthly capaa

ity products, our Independence facff

ity market where capac

ity forff
a

city auctions.

a
capac

a

a

7

West SegSS megg

nt

Our West segment is comprised of two power generation facilities totaling 1,130 MW of generation capac

a

ity and the first

two phases of a battery ESS facff

ility totaling 400 MW in CAISO, all of which are located in California.

ISO/RTO
CAISO
CAISO
CAISO

Technology
CCGT
Battery
CT

Primary Fuel
Natural Gas
Renewable
Fuel Oil
Total West Segmen

t

Number of Facilities
1
1
1
3

Net Capacity (MW)

1,020
400
110
1,530

We plan to develop an additional 350 MW in the third phase of our battery ESS at our Moss Landing Power Plant site

with an estimated commercial operation date in the summer of 2023.

CAISO — CAISO is an ISO that manages the flow of electricity to approximately 32 million customers primarily in

California, representing approximately 80% percent of the state's electric load.

Energy is priced in CAISO utilizing an LMP methodology. The capac

ity market is comprised of Generic, Flexible and
Local Resource Adequacy (RA) Capacity and is administered by the California Public Utilities Commission. Unlike other
In November
centrally cleared capac
ity auction for annual, monthly, and intra-month procurement to cover forff
2016, CAISO implemented a voluntary capac
d in October 2015, is a
deficiencies in the market. The voluntary Competitive Solicitation Process, which FERC approve
apacity.
ity Procurement Mechanism (CPM) and provides another avenue to sell RA cRR
modification to the Capac

ity markets, the resource adequacy market in California is a bilaterally traded market.

a

a

a

a

a

Sunset Segment

Our Sunset segment is comprised of 10 power generation facff

ity in MISO,
PJM and ERCOT. The Sunset segment represents plants with announced retirement plans between 2022 and 2027 that were
previously reported in the ERCOT, PJM and MISO segments. See Note 4 to the Financial Statements for more information
related to these planned generation retirements.

ilities totaling 7,486 MW of generating capac

a

ISO/RTO
ERCOT
MISO
MISO
PJM

Technology
ST
ST
CT
ST

Primary Fuel
Coal
Coal
Natural Gas
Coal
Total Sunset Segment

Number of Facilities
1
4
2
3
10

Net Capacity (MW)

650
3,187
221
3,428
7,486

See Texas Segme

SS

nt above for a discussion of the ERCOT ISO and East Segment above for a discussion of the PJM RTO.

MISO — MISO is an RTO that manages the flow of electricity from approximately 202,000 MW of generation capac

ity
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.

a

MISO dispatches power plants to meet system energy and reliabila

ity needs and settles physical power deliveries at LMPs.
Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time
and day-ahead auctions. Energy prices vary among the regional zones in MISO and are largely influenced by transmission
evaluating the perforff mance of the markets and
constraints and fuel supply. An independent market monitor is responsible forff
identifying conduct by market participants or MISO that may compromise the efficiency or distort the outcome of the markets.

MISO administers a one-year Planning Resource Auction for the next planning year fromff

June 1st of the current year to
ity that has not been committed through
May 31st of the following year. We participate in these auctions with open capac
bilateral or retail transactions. We also participate in the MISO annual and monthly financial transmission rights 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.

a

8

Wholesale Operations

Our wholesale commodity risk management group is responsible forff

dispatching our generation fleet in response to
market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleff et 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 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
by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up
loads may be satisfiedff
owing units and peaking units
and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load foll
tion is typically based on the
are dispatched into the ISO/RTO grid in order from lowest to highest variable cost. Price forma
highest variable cost unit that clears the market to satisfy system demand at a given point in time.

ff

ff

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.

Seasonalitll ytt

ed by weather. As a result, our operating results
The demand for and market prices of electricity and natural
are impacted by extreme or sustained weather conditions and may flucff
tuate 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
gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme
and price of natural
tuation may change
winter weather have made, and may make such fluctuations more pronounced. The pattern of this flucff
depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.

gas are affect

ff

t

t

Compem titiii on

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 forff
new and existing generation facilities, new market entrants,
construction of new generating assets, technological advances in power generation, the actions of environmental and other
tors. We primarily compete with other electricity generators and retailers based on our
regulatory authorities, and other facff
ability to generate electric 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 numerous 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 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 appa
property
roximately 19 years, is registered and protected by trademark law and is the only material intellectual
asset that we own. We have also acquired the trade names forff Ambit Energy, Dynegy Energy Services, Homefield Energy,
TriEagle Energy, Public Power and U.S. Gas & Electric through the Ambit Transaction, Crius Transaction and the Merger, as
the case may be. As of December 31, 2021, we have reflected intangible assets on our balance sheet for our trade names of
approximately $1.341 billion (see Note 6 to the Financial Statements).

t

9

Human Capital Resources

As a key component of our core principle that we work as a team, Vistra believes our most valuable asset is our talented,
dedicated and diverse group of employees who work together to achieve our objectives, and our top priority is ensuring their
safety.t One of Vistra's core principles is that we care about our key se
srr , including our employees. We invest in our
people through numerous development and training opportunities, engaging employee programs and generous benefit and
wellness offerings.

l
takehol
der
kk

As of December 31, 2021, we had approximately 5,060 full-time employees, including approximately 1,400 employees

under collective bargaining agreements.

Safety

t

Vistra's mindset around safety i

s exemplim fied by our motto: Best Defense

urt. Our safetyt
culture revolves around people and human performance. We place a high importance on continuous improvement, along with a
on numerous learning and error-prevention tools. To facilitate a learning environment, our various operating plants
ff
keen focus
share their investigations and learnings of all safety events with all operations employees on weekly calls. The information is
presented by front-line employees and supported by management. The lessons from each event are shared across the fleet to
prevent similar incidents at other locations. All personnel at Vistra locations are encouraged to be actively involved in the
constant communication and
safety pt
sustained interaction. In 2021, the generation fleff et conducted more than 57,000 leadership safety et
ngagements across the fleet
continuing our employee driven safety program focused on engagement of all employees.

rocess. Managers are required to participate in safety et

ngagements with staff to enablea

. Everyor ne wins. No oNN ne gets htt

ff

Our focus on reducing the severity of injuries forff

both our employees and contractors who work with us has shown
positive results. In 2021, we did not have any serious injuries, as determined in accordance with industry standards, or fatalities
to our Vistra employees or business partners working at our sites. Although we do not focus on recordable incidents, our Total
Recordable Incident rate (TRIR) for the company was 0.87, better than the second quartile as compared to the Edison Electric
(EEI) 2020 Total Company Injury Data. We encourage near-miss reporting and review of events to promote a learning
Institutet
vents were reviewed by our
environment.
operating teams to promote learning across the fleff et.

earning calls were held every week where near-miss and safety et

In 2021, safety l

t

t

All Vistra employees are covered by our safety pt

rogram. Corporate and retail employees are required to complete
opics through our online learning management system. Employees who are located at a power plant
periodic training on safety t
are required to complete trainings based on job function, which is also tracked through our central learning management
In addition, the Company engages an independent third-party conformity assessment and certification vendor to
system.
manage adherence to our safety st
tandards for all vendors and contractors who work at our plants. In addition, we work closely
with our suppli

ers and contractors to ensure our safety practices are upheld.

u

rograms and comply with OSHA regulations.

All of our power plant facilities have effective health and safety pt

In
addition to compliance, our generation fleet has a total of 12 plants that have been awarded the Voluntary Protection Program
nd health management systems and for
(VPP) Star designation by the OSHA for superior demonstration of effective safety at
our industry. Four additional plants have submitted
maintaining injury and illness rates below the national averages forff
is the highest designation of OSHA's Voluntary Protection
applications and are awaiting review by the OSHA. VPP Star statust
Programs. The achievement recognizes employers and workers who have implemented effecff
nd health management
tive safety at
systems and maintain injury and illness rates below national Bureau of Labor Statistics averages for their respective industries.
years.
These sites are self-sufficient in their ability to control workplace hazards and are reevaluated every three to fiveff
Additionally, 31 of our power plants and mine locations have adopted a proactive Behavior Based Safety at
ch to safetyt
a
which focuses on identifying and providing feedback on at-risk behaviors observed.

pproa

In 2021, we continued our COVID-19 protections and protocols ensuring the safety of all of our employees.

Diversityii

, Eyy

quityii and Inclusion

We recognize the value of having a diverse and inclusive workforce. Our diversity includes all the ways we differ, such
as age, gender, ethnicity and physical appe
arance, as well as underlying differences such as thoughts, styles, religions,
nationality, education and numerous other traits. Creating and maintaining an environment where differences are valued and
respected enhances our ability to recruit and retain the best talent in the marketplat
ce and to provide a work environment that
allows all employees to be their best.

a

10

Vistra's diversity is evolving, and our Board and management are leading by example. Currently, three of the ten Board
members are women, and two of the ten are ethnically diverse. Overall, 28% of the Company's workforce is ethnically diverse.
Women currently hold 26% of the Company's senior management positions, and ethnically diverse employees represent 27% of
senior management.

During 2021, we launched multiple initiatives to unlock the full potential of our people - and our company - through our
diversity, equity, and inclusion efforts. We named our first Chief Diversity Officer in January 2021 who sponsors Vistra's
shed in 2020. We continued to expand our Employee
employee-led Diversity, Equity and Inclusion Advisory Council, establia
Resource Groups (ERG) to promote the appreciation of and communicate awareness of diverse employee groups and
communities and their contribution to the overall success of the organization, both internally and externally. Seven new ERGs
were forff med in 2021, bringing the total number to twelve. New ERGs represent not only diverse cultures,
but also employees
with disabilities, the LGBTQ+ community and employees engaged in innovation. Further initiatives were launched to support
the education, recruitment and retention of current and future employees, with particular emphasis being placed on driving
equal access to opportunities throughout the organization. Hiring manager training was developed and deployed to train
managers on the importance of skills based hiring and inclusive recruiting processes, and we continue to work with Basic
Diversity to develop training for employees to identify bias and develop strong inclusive leaders.

t

our
Vistra is active in our communities to promote inclusivity. Vistra's supply chain diversity initiative seeks to reflect
customer base and workforce compositions through creating a diverse supply chain. Through a new partnership with
Disability:IN, the leading nonprofit resource for business disability inclusion worldwide, Vistra expanded its commitment to an
inclusive global economy. Further, in the second year of Vistra's $10 million five-year commitment to support underserved
communities, Vistra provided funding
to educational and economic development nonprofits around the country working to
transform underserved communities for the better.

ff

ff

Training and Development

We believe the development of employees at all levels is critical to Vistra's current and future success. We have launched
key programs to develop leaders at all levels of the organization, including monthly leader meetings for director-level
employees focusing on gaining a deeper understanding of Vistra's strategy, developing cross-functional relationships and
interacting with senior leadership of the company. Essentials in Leadership provides first
time managers with skills to lead
organizations in situational leadership, business acumen, identification of communication styles and inclusive communication
practices, and exposes them to best practices fromff
across the company. We also revised multiple leadership programs to
continue virtual

ly while we continue with remote work during the current pandemic.

ff

t

Vistra also provides many other training and development programs to help grow and develop employees at every level,
including online learning platform courses, learning management system courses, recorded webinars and presentations, self-
paced development and employee-specific skill training. Thousands of web-based targeted courses are available to all
employees, and the company further supports employees in completing thousands of hours of professional training to support
their respective professional licenses, including accounting, legal and nuclear. In 2021,
continuing education requirements forff
Vistra launched a forma
to all employees to focus on topics like organizational knowledge, career
ff
ion and leadership. Over 600 employees participated in 2021 and logged over
development, individual development, collaborat
4,000 hours of development.
-time employees, other than those in a collective bargaining unit, receive a
ff
formal performance review guiding development and improving results of the business.

l mentoring program availablea

In addition, all full

a

ll
Emplm oye

e Benefitsii

t

compensation structure,

Maintaining attractive benefits and pay are important for recruiting and retaining talent. We are committed to maintaining
an equitablea
including performing annual salary reviews by employee category level within significant
locations of operations. Eligible full- and part-time employees are provided access to medical, prescription drug, dental, vision,
life insurance, accidental death and dismemberment, long-term disability coverage, accident coverage, critical illness coverage
and hospital indemnity coverage. Regular full
-time employees are eligible for short-term disability benefits, and all employees
are eligible for the employee assistance program, parental leave, maternity leave and a 401(k) plan through which the Company
matches employe

e contributions up to 6%.

m

ff

11

Wellnell

ss

We believe a healthy workforce leads to greater well-being at work and at home. To help keep our workforce healthy, we
offer access to on-site medical clinics at six locations. Our healthcare plans are also designed to reward employees for getting
In addition, our employee medical plans promote
annual physicals, age and gender health screenings and immunizations.
mental health and emotional wellness and offer resources forff
employees seeking assistance. Fitness centers in multiple
facilities offer cardio equipment, a selection of free weights and exercise mats. While deferred at times during COVID-19, our
employee-led wellness team engages our people to get active and support causes that promote healthy living. With support
from the company, the wellness team covers the registration costs forff
employees to participate in running and cycling events
throughout the year.

u

Environmental Regulations and Related Considerations

We are subject

to extensive environmental regulation by governmental authorities,

including the EPA and the
lized or proposed several regulatory
environmental regulatory bodies of states in which we operate. The EPA has recently finaff
shing new requirements for control of certain emissions from sources, including electricity generation facilities.
actions establia
See Item 1A. Riskii Factors for additional discussion of risks posed to us regarding regulatory requirements. See Note 13 to the
Financial Statements for a discussion of litigation related to EPA reviews.

nd the Environment and Restoring Science to Tackl

In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public
Health att
e the Climate Crisis (the Environment Executive Order) which
directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take
action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions
discussed below are now subject to this review.

TT

ll
Clima

te Change

There is continuing attention and interest domestically and internationally about global climate change and how GHG
s, primarily by
emissions, such as CO2, contribute to global climate change. GHG emissions from the combustion of fossil fuel
our coal-fueled-generation plants as well as our natural
gas-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 approxi
mately 108 million short
tons of CO2 in the year ended 2021.

a

ff

t

To manage our environmental impact fromff

our business activities and reduce our emissions profile, Vistra set emissions
reduction targets. Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO2 equivalent emissions by 2030 as
compared to a 2010 baseline with a long-term goal to achieve net-zero carbon emissions by 2050, assuming necessary
advancements in technology and supportive market constructs and public policy. In furtherance of Vistra's efforts to meet its
net-zero target, Vistra expects to deploy multiple levers to transition the company to operating with net-zero emissions,
including decarbonization of existing business lines and diversification into low-emission businesses, primarily renewables and
energy storage. We have already taken or announced significant steps to transform our generation portfolio and reduce the
emissions profile of our generation fleet, including:

•

•

•

Solar Development
have announced our plans to develop:

o

Projectstt — We began commercial operation of our 180 MW Upton 2 solar facility in 2018. We

◦

◦

up to 768 MW of solar generation facilities in Texas with expected commercial operation dates during
2022-2023, and
300 MW of solar generation facilities at retired or to-be retired plant sites in Illinois with expected
commercial operation dates ranging from 2023 to 2025.

Storage Projectstt — We began commercial operation of our 10 MW battery ESS at our Upton 2 solar
Battery Energyr
facility in 2018 and our 400 MW of battery ESSs at our Moss Landing facility in 2021. We have announced our
plans to develop:

◦
◦

◦

260 MW of battery ESS in Texas with an expected commercial operation date in 2022;
150 MW of battery ESS at retired or to-be-retired plant sites in Illinois with expected commercial operation
dates ranging from 2023 to 2025, and
350 MW of battery ESS in California with an expected commercial operation date in 2023.

Acquisition of CCGTs — In 2016 and 2017, we acquired 4,042 MW of CCGTs in Texas.
15,448 MW of CCGTs across various ISOs/RTOs in connection with the Merger.

In 2018, we acquired

12

•

Retirements of Fossil Fuel Generation — In 2018, we retired 4,167 MW of lignite/coal-fueled generation facilities in
Texas. In 2019, we retired 2,068 MW of coal-fueled generation facilities in Illinois. We expect to retire an additional
7,486 MW of fossil-fueled generation facilities in Illinois, Ohio and Texas no later than year-end 2027.

See Note 3 to the Financial Statements forff

discussion of our solar and battery energy storage projects and Note 4 to the

Financial Statements for discussion of our retirement of generation facilities.

GHG Emissions

Clean Energy (ACE) rule. The ACE ruler

that repealed the Clean Power Plan (CPP) that had been finaff

In July 2019, the EPA finalized a rulerr
lized in 2015 and
shed new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the
establia
developed emission guidelines that states must use when developing plans
Affordablea
In response to challenges brought by
to regulate GHG emissions from existing coal-fueled electric generating units.
the District of Columbia Circuit (D.C. Circuit Court)
Environmental groups and certain states, the U.S. Court of Appeals forff
vacated the ACE ruler
, including the repeal of the CPP in, January 2021 and remanded the rule to the EPA for further action. In
October 2021, the U.S. Supreme Court granted four petitions for certiorari of the D.C. Circuit Court's decision and consolidated
oral argument in February 2022. Additionally, in January
the cases for review. The case is now fully briefed and scheduled forff
2021, the EPA, just prior to the transition to the Biden administration, issued a finaff
a significant contribution
finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. In
and remand of the GHG
April 2021, the D.C. Circuit Court granted the EPA's unopposed motion for voluntary vacaturt
significant contribution rule. The ACE ruler
and the rule on significant contribution are subject to the Environment Executive
.
Order discussed above

setting forth

l rulerr

a

ff

State Regulation of GHGsHH

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

regulatory programs intended to reduced

emissions of GHGs from stationary sources as a means of addressing climate change.

e

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 fromff
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 ruler

including an additional 30 percent reduction in the CO2 annual cap ba
conducting its third program review to be completed in 2022 which may include an updated model rule.

with changes to the CO2 budget trading program,
y the year 2030, relative to 2020 levels. RGGI is currently

Our generating facilities in Connecticut, Maine, Massachusetts, New Jersey, New York and Virginia emitted
approximately 8.5 million tons of CO2 during 2021. The spot market price of RGGI allowances required to operate these
facilities as of December 31, 2021 was approximately $13.68 per allowance. The spot market price of RGGI allowances
2022 was approximately $14.01 per allowance on February 22, 2022. While
required to operate our affected facilities during
the cost of allowances required to operate our RGGI-affected facff
ilities 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.

d

Massachusettstt — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final
shing an annual declining limit on aggregate CO2 emissions from 21 in-state fossil-fueled electricity generation
rules establia
units. The rules establia
sh an allowance trading system under which the annual aggregate electricity generation unit sector capa
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 forff
2018. Beginning in 2019, the allocation process transitioned to a competitive
auction process whereby allowances are partially distributed through a competitive auction process and partially distributed
based on the process and schedule establia
shed by the rule. Beginning in 2021, all allowances were distributed through the
auction. Limited banking of unused allowances is allowed.

13

r
Virgini

a — In May 2019, the Virginia Department of Environmental Quality issued a finaff

a
cap-and
trade program for fossil-fueled electricity generation units, including our Hopewell facility, beginning in 2020. The program is
based on the RGGI proposed 2017 model rulerr
and linked Virginia to RGGI in 2021. The Governor of Virginia issued an
RGGI; however, the Virginia General
Executive Order in January 2022 to begin the process of removing the state fromff
Assembly would need to modify the law to exit the program. At this time, no new laws have passed and Virginia remains in
RGGI.

to adopt a carbon

l rulerr

r

New JersJJ

ey — 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, and New Jersey forma
lly rejoined RGGI in June 2019.
In June 2019, New Jersey adopted two rules that govern New Jersey's reentry into the RGGI auction and distribution of the
RGGI auction proceeds.

ff

California — Our assets in California are subject to the California

Global Warming Solutions Act, which required the
ff
a Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state
Californi
ff
to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establia
shing 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. 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-t

rade program through 2030 and the CARB
adopted amendments to its cap-and-t
ework for extending the
rade regulations that, among other things, establia
program beyond 2020 and linking the program to the new cap-a and-trade program in Ontario, Canada beginning in January
2018.

shed a framff

a

a

Air Ei miEE ssio

ii

ns

The Clean Air Act (CAA)A

The CAA and comparablea

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 SO2
emissions and in some regions 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 desulfuriz
ation (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.

ff

Regional

e

Haze — Reasonable Progress and Best Available Retrofit

tt

Technology (BARBB T) for Texas

ee

The Regional Haze Program of the CAA establia

shes "as a national goal the prevention of any future, and the remedying of
man-made pollution."
any existing, impairment of visibility in mandatory class I fede
reasonable progress for Class I
There are two components to the Regional Haze Program. First, states must establish goals forff
eral areas in
federal areas within the state and establia
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.

sh long-term strategies to reach those goals and to assist Class I fedff

ral areas which impairment results fromff

ff

t

14

l rulerr

In October 2017, the EPA issued a finaff

addressing BART for Texas electricity generation units, with the rule serving
as a partial approval of Texas' 2009 State Implementation Plan (SIP) and a partial Federal Implementation Plan (FIP). For SO2,
the rule establia
shed 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 the 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. For NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rulerr
approved
Texas's SIP that determines that no electricity generation units are subject to BART forff
particulate matter. In August 2020, the
but also included additional revisions that were proposed in
EPA issued a finaff
November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit Court, where
, and the retirements of our Monticello, Big
we have intervened in support of the EPA. We are in compliance with the rulerr
is subject to the Environment Executive
Brown and Sandow 4 plants have enhanced our ability to comply. The BART ruler
. The challenges
Order discussed above, and the EPA has stated it is starting a proceeding for reconsideration of the BART ruler
in the D.C. Circuit Court have been held in abeyance pending the EPA's action on reconsideration.

affirming the prior BART finaff

l ruler

l ruler

National Ambient Air Quality Stt

taS ndards (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.

SO2 Designati

i

ons for Texas

ee

u

u

In December 2017, the TCEQ submi

tted a petition for reconsideration to the EPA.

the Fifth Circuit (Fifth Circuit Court). Subsequent

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation
plant and our now-retired Big Brown and Monticello 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 U.S. Court of Appeals forff
ly, 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 August 2019, the
EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous
nonattainment designations and each area at issue would be designated unclassifiablea
In August 2020, the EPA issued a
.
Finding of Failure for Texas to submit an attainment plan. In May 2021, the EPA finalized a "Clean Data" determination for
the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring
In June 2021, the EPA published two notices; one that it was withdrawing the
data supporting an attainment designation.
August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to
reconsider the original nonattainment designations. We, along with the State of Texas, challenged that EPA action and have
consolidated it with the pending challenge in the Fifth Circuit Court, with the matter likely being fully briefed by March 2022.
In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed
order to reduce SO2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduces emission
limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. The
TCEQ's SIP action was finalized in February 2022 and will be submitted to the EPA forff

review and approval.

Ozone Designati

i

ons

l ruler

The EPA issued a finaff

in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. Areas
ility in Illinois and our Wise, Ennis
surrounding our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facff
and Midlothian faci
lities in Texas were designated marginal nonattainment areas in June 2018 by the EPA with an attainment
deadline of August 2021. The EPA is required to take action on areas that did not attain by that date by bumping up the region
to a "moderate" designation with an attainment deadline of August 2024. States will be required to develop SIPs to address
emissions in areas with a higher (more stringent) classification.

ff

In 2016, the EPA finalized the Cross-State Air Pollution Rule Update (CSAPR Update) to address 22 states' obligations
with respect to the 2008 ozone NAAQS. In 2019, following challenges by numerous parties, the D.C. Circuit Court found that
the CSAPR Update did not fully address certain states' 2008 ozone NAAQS obligations. In October 2020, the EPA proposed
an action to address the outstanding 2008 ozone NAAQS obligations in response to the D.C. Circuit Court's 2019 ruling. Vistra
subsidia
l rulr e in the Federal Register
u
on April 30, 2021 that reduces ozone season NOX budgets in certain states. We do not believe that the final rulrr e causes a
material adverse impact on our future financial results. These actions are subject to the Environment Executive Order discussed
above.

ries fileff d comments on that rulerr making in December 2020, and the EPA published a finaff

15

Coal Combustion Residuals (CCR)/GR roundw

GG

ater

The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at
in surface impoundments. Each of our coal-fueled plants

power generation facilities in dry form in landfills and in wet formff
has at least one CCR surface impoundment. At present, CCR is regulated by the states as solid waste.

CC
Coal Combust

ion Residualsll

The EPA's CCR ruler

, which took effect in October 2015, establia

shes minimum federal requirements for the construction,
retrofitting, operation and closure of, and corrective action with respect to, existing and new CCR landfills and surface
impoundments, as well as inactive CCR surfaceff
impoundments. The requirements include location restrictions, structural
integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping
tors. The Water
and notification. The deadlines for beginning and completing closure vary depending on several facff
Infrastructure Improvements forff
EPA
review and approval of state CCR permit programs.

the Nation Act (the WIIN Act), which was enacted in December 2016, provides forff

t

In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR
establishing a
rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a finaff
allows a
deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final ruler
and either a
generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capac
conversion to comply with the CCR rulrr e is underway or retirement will occur by either 2023 or 2028 (depending on the size of
the impoundment at issue). Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance
extensions under both conversion and retirement scenarios. In November 2020, environmental groups petitioned forff
review of
this rulerr
in the D.C. Circuit Court, and Vistra subsidiaries filff ed a motion to intervene in support of the EPA in December 2020.
that would allow an alternative liner demonstration for certain qualifying
Also, in November 2020, the EPA finalized a rulerr
facilities. In November 2020, we submitted an alternate liner demonstration for one CCR unit at Martin Lake. In August 2021,
we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following
In January 2022, the EPA determined that our conversion and
announcement that Zimmer will close by May 31, 2022.
determination on any of those
retirement applications for our CCR facff
applications.

ilities were complete but has not yet made a final

ity is availablea

l ruler

a

ff

MISO — 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. These violation notices
remain unresolved; however, 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 have completed closure activities at those ponds at our Baldwin facility.

a

In May 2018, Prairie Rivers Network (PRN)RR

At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rulerr

until the aforementioned
D.C. Circuit Court decision in August 2018, 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, and we submitted revised plans in
2014. In May 2017, in response to a request from the IEPA forff
additional information regarding the closure of these Vermilion
surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing
options.
filed a citizen suit in federal court in Illinois against our subsidiary
Dynegy Midwest Generation, LLC (DMG), 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
the Seventh Circuit affiff rmed the district court's
judgment was entered in our favor. In June 2021, the U.S. Court of Appeals forff
dismissal of the lawsuit, but stated that PRN may refile. In April 2019, PRN aRR
lso filff ed a complaint against DMG before the
Illinois Pollution Control Board (IPCB), alleging that groundwater flows
allegedly associated with the ash impoundments at the
Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to
1992. In July 2021, we answered that complaint, and this matter is in the very err

arly stages.

ff

16

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeeff
n
ral
facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the fede
. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface
CCR rulerr
to the
impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referredr
Illinois Attorney General.
In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filff ed a
complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation
notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic
river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim
consent order, DMG is required to evaluate the closure alternatives under the requirements of the newly implemented Illinois
Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during
the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby
Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a
certain distance of the impoundments. These proposed closure costs are reflected in the ARO in our condensed consolidated
balance sheets (see Note 21 to the Financial Statements).

ff

In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state
requirements forff
the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a
series of guidelines, rules and permit requirements for closure of ash ponds. Under the final rulr e, which was finalized and
became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the
does not mandate closure by
IEPA for the selection of the best method for coal ash remediation at a particular site. The rulerr
removal at any site. In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final
rule.
We fileff d our opening brief in October 2021. Other parties have also filed appeals of certain provisions of the final rulrr e.
rr
In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed
construction permit applications for three of our sites in January 2022.

For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are
ilities, we may incur significant costs that could have a material adverse effect on our
required at any of our coal-fueled facff
financial condition, results of operations, and cash flows. The Illinois coal ash rule was final
ized in April 2021 and does not
require removal. However, the rule will require us to undertake further site-specific evaluations required by each program. We
will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be
required under the Illinois rule until permit applications have been submitted and approved by the IEPA. However, the
currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO liabia lities, reflect
the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the
environment for each location.

ff

Water

The EPA and the environmental regulatory bodies of states in which we operate have jurisdiction over the diversion,
impoundment and withdrawal of water forff
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
ilities in operation and
relating to these activities. We believe we hold all required permits relating to these activities for facff
have applied for or obtained necessary permits forff
facilities under construction. We also believe we can satisfy the
requirements necessary to obtain any required permits or renewals.

II

S
e Skk

truct

Cooling WateWW r Intak

ures — 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 capac
t the best technology available for minimizing adverse
environmental impacts. Although the rule does not mandate a certain control technology, it does require site-specificff
assessments of technology feasibility on a case-by-case basis at the state level.

ity of cooling water intake structures

reflecff

a

t

At this time, we estimate the cost of our compliance with the cooling water intake structure rulerr

to be minimal at our
Illinois plants due to the planned retirements of those plants by 2027. 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 rulrr e and potential plant retirements.

17

ff

Effluent Limitation Guidelines (ELGs)GG — In November 2015, the EPA revised the ELGs forff

steam electricity generation
facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as fluff e
gas desulfuriz
ation (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filff ed petitions for
review of the ELG rulrr e, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions
requesting reconsideration of the ELG rulrr e and administratively stayed the rule's compliance date deadlines. In August 2017,
the EPA announced that its reconsideration of the ELG rulrr e would be limited to a review of the effluent limitations applicable
to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rulrr e forff
cation of effluent limitations for FGD and bottom ash wastewaters. Based on these administrative developments, the
a
the appli
Fifth Circuit Court agreed to sever and hold in abeyance challenges to those effluent limitations. The remainder of the case
proceeded, and in April 2019 the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rulerr
pertaining to
effluent limitations forff
in October 2020 that extends the
both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state
compliance date forff
permitting agency. Additionally, the final rulrr e allows for a retirement exemption that exempts facff
ilities certifying that units
will retire by December 2028 provided certain effluent limitations are met.
In November 2020, environmental groups
review of the new ELG revisions, and Vistra subsidiaries filff ed a motion to intervene in support of the EPA in
petitioned forff
and moved to hold the 2020 ELG revision
December 2020. In July 2021, the EPA announced its intent to revise the ELG rulerr
litigation in abeyance pending the EPA's completion of its reconsideration rulemaking. Notifications were made to Texas,
Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13,
2021.

legacy wastewater and leachate. The EPA published a finaff

l ruler

Radiodd active Wastett

The nuclear industry has developed ways to store used nuclear fuel

ff

on site at nuclear generation facilities, primarily using
currently in operation in the U.S.
on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear

reprocessing or disposal of used nuclear fuel

ff

dry cask storage, since there are no facilities forff
Luminant stores its used nuclear fuel
fuel storage capabi

a

ff

lity is sufficient for the foreseeable futff ure.

t

18

Item 1A. RISK FACTORS

Summary of Risk Factors

The following summarizes the principal facff

tors that make an investment in our company speculative or risky, all of which
are more fully described in the Risk Factors section below. This summary should be read in conjunction with the Risk Factors
section and should not be relied upon
ng our business. The following factors
as an exhaustive summary of the material risks faci
could result in harm to our business, financial condition, results of operations, cash flows, and prospects, among other impacts:

u

ff

Market, Finanii

ciali

and Economic Risks

•

Our revenues, results of operations and operating cash flows are affected by price flucff
market and other market facff

tors beyond our control.

tuations in the wholesale power

• We purchase natural

for our generation facilities, and higher than expected fuel
costs or disruptions in these fuel markets may have an adverse impact on, our costs, revenues, results of operations,
financial condition and cash flows.

gas, coal, fuel oil, and nuclear fuel

ff

t

• We have retired, announced planned retirements of, and may be force

ff

d to retire or idle additional underperforming

•

•

•

•

generation units which could result in significant costs and have an adverse effecff

t on our operating results.

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.

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

and/or state or fede

ff

t

Our results of operations and financial condition could be materially and adversely affected if energy market
participants continue to construct new generation facilities or expand or enhance existing generation facilities despite
relatively low power prices and such additional generation capac

ion in wholesale power prices.

ity results in a reductd

a

The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures,
contain restrictions and limitations that could affect our ability to operate our business, our liquidity, and our results
of operations, and any failure to comply with these restrictions could have a material adverse effect on us.

• We may not be able to complete future acquisitions on favorablea

terms or at all, successfully integrate future
acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which
could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy.

•

•

Our ability to achieve the expected growth of our Vistra Zero portfolio, consisting of our solar generation, ESS, and
other
to substantial capital requirements and other significant
uncertainties.

renewables development projects,

is subject

Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or
increased taxes or fees, could have a material adverse effect on our financial condition, results of operations and cash
flows.

• We are required to pay the holders of TRA RRR

ights forff

certain tax benefits, which amounts are expected to be

substantial.

Regue

latorytt

and Legie slati

ii

ve Risks

•

•

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

Our cost of compliance with existing and new environmental laws could have a material adverse effecff

t on us.

19

•

•

Pending or proposed laws or regulations, including those proposed or implemented under the Biden administration,
could have a material adverse effect on our businesses, results of operations, liquidity and financial condition.

Changes to laws, rules or regulations related to market structures
material adverse effect on our businesses, results of operation, liquidity and financial condition.

in the markets in which we participate may have a

t

• 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.

•

Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to
significant liabilities and reputational damage that could have a material adverse effecff

t on us.

Operational Risks

ii

•

•

•

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

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

The operation of our businesses is subject to information security and operational technology risks, including
cybersecurity breaches and failure of critical information and operations technology systems. Attacks on our
infrastructuret
that breach cyber/data security measures could expose us to significant liabilities, reputational damage,
regulatory action, and disrupt business operations, which could have a material adverse effecff

t on us.

• We may suffer material losses, costs and liabilities due to operational risks, regulatory risks, and the risk of nuclear

accidents arising from the ownership and operation of the Comanche Peak nuclear generation facility.

•

The operation and maintenance of power generation facilities and related mining operations are capita
involve significant risks that could adversely affecff

t our results of operations, liquidity and financial condition.

al intensive and

• We may be materially and adversely affected by obligations to comply with federal and state regulations, laws, and
other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and
monitoring relating to CCR.

• We are subjeu

ct to, and may be materially and adversely affected by, the effects of extreme weather conditions and

seasonality.

•

•

The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a
material and adverse effect on our business, financial condition, results of operations and cash flows.

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

ii
Risks

Relatedtt

to Our Struc

tt

ture and Ownership oii

f oo ur Common Stock

•

Evolving expectations from stakeholders,
including climate change and
sustainability matters, and erosion of stakeholder trust or confidence could influence actions or decisions about our
company and our industry and could adversely affecff

t our business, operations, financial results, or stock price.

including investors, on ESG issues,

20

ll

Please carefully consider the following discussion of significant factors, events, and uncertainties that make an
tors, in addition to others specifically addressed in Item 7. Management's
investment in our securities risky. These facff
Discussion and Analysis
of Financial Condition and Results of Operations (MD&A)&& , provide important information for the
understanding of our forward-looking statements in this annual report on Form 10-K. If one or more of the factors, events and
uncertainties discussed below or in the MD&A were to materialize, our business, results of operations, liquidity, financial
In addition, if one or more of such
condition, cash flows, reputation or prospects could be materially adversely affected.
those contained
factors, events and uncertainties were to materialize, it could cause results or outcomes to differ materially fromff
risks and
ff
in or implied by any forward-looking statement in this annual report on Form 10-K. There may be further
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, 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 securities (including our common stock) to lose all
or a substantial portion of their investment.

Market, Financial and Economic Risks

Our revenues, resultsll
power market and other market facff

tors beyond our control.ll

of operations and operatingii

cash flowff

s gw enerally all

re affected by pb

ff
rice fluct

uations in the wholesll ale

t

on capita

We are not guaranteed any rate of returnt

al investments in our businesses. We conduct integrated power
generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales
gas to end users and commodity risk management. Our wholesale and retail businesses are to some
of electricity and natural
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 is subject to wholesale power price moves, which may be significant. As
a result, our revenues, results of operations and operating cash flows depend in large part upon wholesale market prices for
gas, uranium, lignite, coal, fuel, and transportation in our regional markets and other competitive markets in
electricity, natural
which we operate and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of
regulatory authorities.

t

t

a

ity, ancillary services, natural

Market prices for power, capac

gas, coal and fuel oil are unpredictable and may flucff

tuate
t
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 occur as a result of the
construction of new power generation sources, as we have observed in recent years. During periods of over-supply, electricity
prices might be depressed. For example, the cost of electricity from renewable resources, such as solar, wind and battery
In many instances, energy from these sources are bid into the
storage systems, has dropped substantially in recent years.
all power
relevant spot market at a price of zero or close to zero during certain times of the day, lowering the clearing price forff
wholesalers in such market. Also, at times there is 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.

t

Extreme weather events can also materially impact power prices or otherwise exacerbate conditions or circumstances that
result in volatility of power prices. For example, in February 2021, the U.S. experienced Winter Storm Uri and extreme cold
temperatures
gas
ity of renewable generation across the
used in our electric power generation business, and the cold further limited the availabila
region contributing to extremely high market prices for natural
gas and electricity, which resulted in substantial increases in the
costs to procure sufficient fuel supply and increased collateral posting requirements.

in the central U.S., including Texas. This severe weather event substantially increased the demand for natural

t

t

a

The majoa rity of our facilities operate as "merchant" facff

ilities without long-term power sales agreements. As a result, we
ity and ancillary services into the wholesale energy spot market or into other wholesale and
largely sell electric energy, capac
al investments. Consequently,
retail power markets on a short-term basis and are not guaranteed any rate of returnt
there can be no assurance that we will be able to sell any or all of the electric energy, capac
ity 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
ity and fuel. Given the volatility of commodity power prices, to the extent we are
a
prevailing market prices for power, capac
unable to hedge or otherwise secure long-term power sales agreements forff
the output of our power generation facilities, our
revenues and profitability will be subjeu
ct to volatility, and our financial condition, results of operations and cash flows could be
materially adversely affect

on our capita

ed.

a

ff

21

We purchase natural gas, coal, fll uel
volati
, oyy
ll
financial conditiontt

and cash flows.

liii tyii

ff

ll

r disrdd uption in these fuel markets may have an adverse impactm

on our costs, revenues, resultsll

oil, all nd nuclear fuel forff

our generation faciliii tiii es, as nd higher than expectedtt

fuel costs,
of operations,

t

ff

ff

gas, coal, fuel

We rely on natural

oil, and nuclear fuel

for the majoa rity of our power generation facilities. Delivery orr
f
these fuels to the facilities is dependent upon the continuing availability of such fuel
ity of contractual
counterparties as well as upon the infrastructure (including mines, rail lines, rail cars, barge facilities, roadways, riverways and
gas pipelines) available and functioning to serve each generation facility. As a result, we have experienced, and remain
t
natural
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, if a counterparty fails to perform or if there is a disruption in the fuel delivery i
Certain of our
nfrastructure.
generation facilities rely on a limited number of counterparties, such as natural
gas suppliers and railcar companies, to provide
the necessary fuel. Disputes relating to or non-performance of contractual arrangements, have resulted in, and may continue to
result in adverse impacts to our costs, revenues, results of operations, financial condition, and cash flows.

s and financial viabila

rr

ff

t

t

ff

supplier or transporter. Fuel costs (including diesel, natural

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
majea ure events or the default of a fuel
gas, lignite, coal and nuclear
electricity does not always change at the same rate as changes in fuel costs, and
fuel) are volatile, and the wholesale price forff
disruptions in our fuel supplies may therefore require us to find alternative fuel sources at costs which may be higher than
planned, 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. Long-term and short-term contracts are subject to risk of non-delivery or claims of force
majea ure, which may impact our ability to economically recover the value of the contract.
In addition, we purchase and sell
gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting our
t
natural
obligations. Further, any changes in the costs of natural
or transportation rates and changes in
ff
gas, coal, fuel
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 favorablea
, or if we are unable to procure these fuels at all, our financial
condition, results of operations and cash flows could be materially adversely affected. For example, supply challenges were
am gong hthe

signifificant lloss expe irienced id in 2021 as a res lult of Wiinter Storm iUri.

iprim yary d idrivers of hthe signi

oil, nuclear fuel

ff

t

t

We also buy significant quantities of fuel

tuate,
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 and operating performance. Volatility in market prices for fuel and electricity results from,
among other
factors:

on a short-term or spot market basis. Prices for all of our fuels flucff

ff

ff

•

•

•
•
•
•

•

•
•
•
•
•

•
•

•
•

t

ff

gas, coal and fuel

and related enrichment and conversion services;

energy commodities and general economic conditions, including impacts of inflation and the relative

demand forff
strength or weakness of U.S. dollar compared to other currencies;
volatility in commodity prices and the supply of commodities, including but not limited to natural
oil;
volatility in market heat rates;
volatility in coal and rail transportation prices;
volatility in nuclear fuel
transmission or transportation disruptions, constraints, congestion, inoperability or inefficiencies of electricity, natural
gas or coal transmission or transportation, or other changes in power transmission infrastructure;
severe, sustained or unexpected weather conditions, including extreme cold, drought and limitations on access to
water;
seasonality;
ff
changes in electricity and fuel
illiquidity in the wholesale electricity or other commodity markets;
importation of liquified natural gas to certain markets;
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 structuret
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 capaa
outages or otherwise reduced output

from our generation facilities or those of our competitors;

usage resulting from conservation efforts,

changes in technology or other factors;

city or efficff
t

and liquidity;

iency;

ff

t

t

22

•

•
•
•
•
•

•

a

ity;

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 capac
local, regional, national, or global supply chain constraints or shortages;
our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
changes in the credit risk, payment practices, or financial condition of market participants;
changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;
pandemics and epidemics (including the impacts thereto, or recovery therefrom), natural
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.

disasters, wars, sabotage,

t

See "Economic downturns would likely have a material adverse effect

ff

on our businesses" for a discussion of potential

risks arising from current U.S. and global economic and geopolitical conditions.

We have retired
generation unitsii which could result ill n s

nnounced planned retireme

ii
ignigg fici

nts of, and may be forced to retireii

tt
dditional
ll
esults.
ant costs and have an adverse effect on our operating rn

or idle all

, add

ii

tt

underperforming

A sustained decrease in the financial results from, or the value of, our generation units has resulted in the retirement or
planned retirement of, and ultimately could result in additional retirements or idling of, generation units. 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. In connection with the closure and remediation of retired generation units,
we have spent, and may in the future spend, a significant amount of money, internal resources and time to complete the required
closure and reclamation, which could have a material adverse effect on our financial and operating performance.

Our assets or positions cannot be fully hedged against
transactions may na

ot work as planned or hedgedd

a
tt
counterpart

changes in c
e

ii
iett s may default

on their oii

tt
bligations.

ommodity ptt

rices and market heat rates, as

nd hedgingn

t

Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notablya
gas prices, because of the expected useful life of our generation assets and the size of our position relative
electricity and natural
to the duration of available markets forff
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
ion of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat
a durat
d
rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favora
or
unfavorably.

blya

a

ff

t

To manage our financial exposure related to commodity price flucff

tuations, we routinely enter into contracts to hedge
gas, lignite, coal, diesel fuel, uranium
portions of purchase and sale commitments, fuel requirements and inventories of natural
and refined products, and other commodities, within establia
shed 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. Given our exposure to risks of commodity price movements, we devote a
considerablea
amount of time and effort to the establishment of risk management policies and procedures, as well as the ongoing
review of the implementation of these policies and procedures. Additionally, we have processes and controls in place that are
designed to monitor and accurately report hedging activities and positions. The policies, procedures, processes and controls in
place may not always function as planned and cannot eliminate all the risks associated with these activities, including
unauthorized hedging activity, or improper reporting thereof, by our employees in violation of our existing risk management
policies and procedures. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected
changes due to weather, natural
tors could cause us to purchase
disasters, consumer behavior, market constraints or other facff
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 facff
tors, the impacts of our commodity hedging activities and risk
management decisions may have a material adverse effect on our business, financial condition, results of operations and cash
flows.

t

23

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 to 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 commodity price risk, those hedges may ultimately prove to be ineffective. Additionally, there may be changes to
existing laws or regulations that could significantly impact our ability to effectively hedge, which may have a material adverse
effect on us.

With the continued tightening of credit markets that began in 2008 and 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,
ons 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.

participation by financial instituti

a

tt

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
, we could be forced to enter into alternative hedging arrangements or
the counterparties to these arrangements fail to performff
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 ISOs/RTOs in
which we operate are also exposed to risks that another market participant may default on its obligations to pay such ISO/RTO
for electricity or services taken, in which case such costs, to the extent not offset by posted security and other protections
available to such ISO/RTO, may be allocated to various non-defaulting ISO/RTO market participants, including us.

ff

We do not apply hedge accountingtt
tt
quarterly

and annual financial results.

ll

to our commodityii

derivativett

transactions,

tt

which may cause increased volati

liii tyii

ll

in our

We engage in economic hedging activities to manage our exposure related to commodity price flucff
commodities. These derivatives are accounted forff

tuations through the
use of financial and physical derivative contracts forff
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
If designated, those contracts are not recorded at fair value. GAAP also permits an entity to
normal purchases and sales.
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 elected not to apply hedge
accounting to our commodity contracts, and we have designated contracts as normal purchases and sales in only limited cases,
such as our retail sales contracts. As a result, our quarterly and annual finaff
ncial results in accordance with GAAP are subject to
significant fluctuat

ions caused by changes in forward commodity prices.

t

Compem titiii on, changes in mii
together withii
ll
cash flows.

ower markets,s
tt
subsidized generation, may have a material adverse effect on our financial condition, resultsll of operations and

arket structure, ae nd/or state or federal interfer

ence in the wholesale

and retail pii

ll

Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale
marketplat
ral 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.

ce may be undermined by changes in market structuret

and out-of-market subsidies provided by fede

ff

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of
regulated utilities, other energy service companies and financial instituti
ity 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 capac
ity based on several competing technologies, as well as power generating facilities
including hydroelectric power, synthetic fuels, solar, wind, wood,
fueled by alternative or renewable energy sources,
geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewabla e
generation increases competition from these types of facilities and out-of-market subsidies to existing or new generation can
undermine the competitive wholesale marketplat
retirement of existing facilities, including those
ce, which can lead to prematuret
owned by us.

ons in the sale of electric energy, capac

a

a

tt

24

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 abla e to respond more quickly to new laws and regulations because of the newer
technology utilized in their facilities or the additional resources derived fromff

owning more efficff

ient facilities.

Other factors may contribute to increased competition in wholesale power markets. We expect that we will continue to
face intense competition from numerous companies, including new entrants or consolidation of existing competitors, in the
industry. Certain fedff
eral 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, including through certain tax benefits,
the construction and development of additional renewabla e resources as well as increases in energy efficiency investments.
Subsidies (or increases thereto) to our competitors could have a material adverse effect on our financial condition, results of
operations and cash flows.

In addition, our retail marketing efforts compete forff

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 fromff
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
If more customers switch to another supplier than
the need to go to the market to cover the incremental supply obligation.
anticipated, the load we must serve will be lower than anticipated and, if market prices of electricity have decreased, our
operating results could suffer.

of operations and financial condition could be material

Our resultsll
continue
ii
power prices and such additional generation capacityii

t new generatiott n facff

to construc

resultsll

tt

tt

ilities or expand or enhance exiee stinii

g gn
in a reduction in wholesale power prices.

and adversely affected ifi energyr market participants
vely low

eneration faciliii tiii es despis teii

ll
relati

lyll

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 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.
Additionally, new or existing market participants without, or with less, fossil fuel
operations may gain additional market share,
or reduce our market share, dued
to evolving expectations and sentiments of key stakeholders, government, and regulatory
authorities regarding our operations and activities.

ff

Economic dowdd

nturns would likel

y hll

ii

ave a material

tt

adverse effect on our businesse

ii

s.

t

a

ity and natural

gas, which can flucff

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including
Increased unemployment of
lower prices for power, generation capac
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.
The convergence of current global conditions,
including sustained inflation, rising interest rates, and the geopolitical climate, could lead to, or accelerate or exacerbate the
occurrence of, a significant economic downturn, leading to changes in consumer and counterparty behavior, higher costs of
capita
al, decreases in the value of our existing long-dated contracts, commodity price increases and volatility, supply chain
shortages, and other adverse impacts to our business. 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.

tuate substantially.

ff

ff

25

ii
Our liquidi
timeii
s of so
the future, which could hll
a
that could negativtt ely all
if our credit ratings
particularly

ffec

ll

tyii needs could be difficult t
tt
ll o s
ignificant fluctuation in commodityii

atisfyii

ll
articularly

s of uo
, pyy
ll
prices, and we may be unable t

duringii

timeii

tt
ncertaint

tt n t
ii
y i
ccess capitaltt

o att

hett

ave a material adverse effect on us. We currently maintain non-investmtt ent grade credit rii

t our abilitll y t
ii

o att
were to be downgraded

ccess capitaltt

n

tt

in the future.ee

on favorable t

rr
ertt ms

ll

tt
or result in higher collat
eral

financialii markets or duringii
on favorable terms or at all in
ii
atings
requirements,

ll

Our businesses are capita

al intensive. In general, we rely on access to finaff

source of liquidity forff
inabila
ity to raise capita
our ability to meet our obligations or sustain and grow our businesses and could increase capita
requirements, any of which could have a material adverse effecff

ncial markets and credit facilities as a significant
our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The
terms, could adversely impact our liquidity and
al or to access credit facilities, particularly on favorablea
al costs and collateral

t on us.

Our access to capita

al and the cost and other terms of acquiring capita

al are dependent upon, and could be adversely

impacted by, various factors, including:

•

•
•
•
•
•
•
•

•
•
•

•
•
•
•

a

ity to obtain or renew credit facff

ilities on favff orable terms or at all;

icable subsidiaries' credit ratings, or credit ratings of its issuances;

al markets conditions, including changes in financial markets that reduce available

general economic and capita
liquidity or the abila
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
a downgrade of Vistra's or its appl
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 abila
credit, security, or collateral requirements, including those relating to volatility in commodity prices;
general credit availability from banks or other lenders for us and our industry peers;
investor and lender confidence in and sentiment of the industry, our business, and the wholesale electricity markets in
which we operate;
a material breakdown in or oversight in effectuat
the occurrence of changes in our businesses;
disruptiu
changes in or the operation of provisions of tax and regulatory laws.

ons, constraints, or inefficiencies in the continued reliable operation of our generation facilities and ESSs; and

ity of such lender(s) to make loans to us;

value or financial or operating results;

ing our risk management procedures;

rr

t

companies that own and operate fossil fuel

There are also increasing financial risks forff

al have become more attentive to sustainable finaff

onal lenders
generation as instituti
or other sources of capita
ncing practices and some of them may seek
commitments on emission reduction targets or expected use or proceeds when providing funding to, or decline to provide
funding for companies who produce or utilize fossil fuel
energy or that have higher levels of GHG emissions. Additionally, the
lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in
climate change not to provide funding for companies in the
nature,
t
al could have a material adverse effect on
broader energy sector. Limitation on our access to, or increases in our cost of, capita
us.

by environmental activists and others concerned about

a

ff

ff

t

In addition, we currently maintain non-investment grade credit ratings. As a result, we may not be able to access capital
e as companies that maintain investment-grade credit ratings or we may be unable
In addition, due to our non-investment grade credit ratings,

on terms (financial or otherwise) as favorabl
to access capita
counterparties request collateral support (including cash or letters of credit) in order to enter into certain transactions with us.

al at all at times when the credit markets tighten.

ff

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 or any of its
subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit ratings.

26

Our indebtedness and the phaseout of LIBOR, oR r thett
tt
affect our abilitll y i
ii
ii eres
increased int
tt
tt
distribu
orff
ll
e f
ii
availabl

tt
future to raise additional
tt
o r
t oii ur abilitll y t

t rates and limi

ee
replac
capitaltt
eact to changesn

tion.

hett

n t

tt

ii

ement of LIBOR withii
to fund our operations.

It could also expose us to t
in the economy,m or our industry,r as well as impactm

tt

nce rate, could all
hett

dversely
risk of
our cash

a difdd ferff

ent refereff

As of December 31, 2021, we had approximately $10.7 billion of total indebtedness and approximately $9.4 billion of

indebtedness net of cash. Our debt could have negative consequences forff

our financial condition including:

•
•

•
•
•

•
•

•

•

ff

purchases which require credit support;

ity to general economic and industry conditions;

increasing our vulnerabila
requiring a significant portion of our cash flows 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
limiting our ability to fund operations or future acquisitions;
restricting our ability to make distributions or pay dividends with respect to our capita
subsidiaries to make distributions to us, in light of restricted payment and other finaff
facilities and other finaff
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
rates of interest;
Vistra Operations Credit Facilities, are at variablea
limiting our ability to obtain additional financing for working capita
expenditures,
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.

debt service requirements, acquisitions and general corporate or other purposes; and

al stock and the ability of our
ncial covenants in our credit

including collateral postings, capital

ncing agreements;

al

t

al for these or other reasons. Furthermore, we may be unable to
We may not be successful in obtaining additional capita
the expiration or termination thereof. Our
terms or at all upon
refinance or replace our existing indebtedness on favorablea
failure to obtain additional capita
al 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.

u

In July 2017, the United Kingdom's Financial Conduct Authority, which regulates LIBOR, announced that it intends to
phase out LIBOR by the end of 2021. LIBOR is the interest rate benchmark used as a reference rate on a portion of our
variable rate debt, including our revolving credit facility and interest rate swapsa .
In November 2020, ICE Benchmark
Administration (IBA), the administrator of LIBOR, with the support of the U.S. Federal Reserve and the United Kingdom's
Financial Conduct Authority, announced plans to consult on ceasing publication of USD LIBOR on December 31, 2021 for
only the one-week and two-month USD LIBOR tenors, and on June 30, 2023 for all other USD LIBOR tenors. While this
announcement extends the transition period to June 2023, the U.S. Federal Reserve concurrently issued a statement advising
banks to stop new USD LIBOR issuances by the end of 2021.
In light of these announcements, the future of LIBOR at this
time is uncertain and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR's
y than in the past or cease to exist. In anticipation of LIBOR ceasing to exist
phaseout could cause LIBOR to perform differentl
for affected tenors, we have amended certain of our agreements with LIBOR as the referenced rate to include an alternative
benchmark rate or suggested fallback language. Additionally, in light of what we believe to be faff vorabla e relationships with
lending and financial counterparties, we expect to seek necessary amendments to our remaining debt instruments and other
agreements which utilize LIBOR as the referenced rate in the normal course. Further, certain of our agreements which utilize
LIBOR as the referenced rate are governed by New York law, and certain of these contracts do not contain any fallback
provisions or otherwise contain fallback provisions that lead to replacement rate based on LIBOR or require polling for
interbank rates. To the extent that we are unsuccessful in our efforts to amend such contracts prior to the LIBOR transition, we
anticipate that the appli
New York legislation would apply to such contracts and would provide a replacement rate forff
inclusion in such contracts.

cablea

a

ff

Notwithstanding our efforts, these changes may result in interest rates and/or payments that do not correlate over time with
the interest rates and/or payments that would have been made on our obligations if LIBOR was available in its current forff m.
lback language. Accordingly,
Any new contracts would need to reference an alternative benchmark rate or include suggested falff
rate debt, which could have an adverse impact on extensions
we could be exposed to increased costs with respect to our variablea
of our credit and/or we might not be fully hedged on the variable rate exposure on our swapped
indebtedness. Any such
a
t on us.
increased costs or exposure could increase our cost of capita

al and have a material adverse effecff

27

The agrea
contain r
ii
operations, and any failure to comply wll

nd instruments governingii
tt
ions
ii
s and limi
tat

ements att
iontt
tt
estrict

tt
ith t
tt hes

ii

tt
that could affect our abilitll y t

our debt, i

tt ncii

ludingii
tt
tions could hll

the Vistra
ii
pero
o o

Operations Credit Faciliii tiii es and indentures,
of
ii
or liquidi

nd resultsll

, ayy

tyii

ate our business,
ave a material adverse effect on us.

ii

e restrictt

The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures,
or react to,
contain restrictions that could adversely affect us by limiting our ability to operate our businesses and plan for,
market conditions or to meet our capita
al needs and could result in an event of default under the Vistra Operations Credit
Facilities and/or indentures. The Vistra Operations Credit Facilities and indentures contain events of default customary for
financings of this type. If we faiff
l to comply with the covenants in the Vistra Operations Credit Facilities and/or indentures and
are unable to obtain a waiver or amendment, or a default exists and is continuing, the lenders under such agreements or notes,
as the case may be, could give notice and declare outstanding borrowings thereunder immediately due and payablea
. The breach
of any covenants or obligations in certain agreements and instruments governing our debt, including the Vistra Operations
Credit Facilities and indentures, not otherwise waived or amended, could result in a default under the applicablea
debt
obligations and could trigger acceleration of those obligations, which in turn could trigger cross defaults under other agreements
governing our debt, and any such acceleration of outstanding borrowings could have a material adverse effecff

t on us.

ff

Certain of our obligati
to provideii

i

such security, it may ra

ons are requiredii
tt
estrict

to be secured by letters
our abilityii

of credit oii
ii
to conduct our business,

tt

r cash, which increase our costs. If wII

which could have a material

tt

e are unablell
adverse effect on us.

r

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 currentl
y use margin deposits, prepayments and letters of credit as credit support for
commodity 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 differen
ce 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 capita
al or other sources of available liquidity to post
as collateral, we may not be able to manage price volatility effectively or to implement our strategy. A material 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.

ff

ff

We may not be able to completell
into ott
ur business, or effectivtt ely i
unantictt

xx
expense

ipatedtt

future acquisitions on favorabl
ermtt
ll
e t
dentify and invest in value-creatingtt

e
integrate
s, assets or projects, which could r
.yy
or delay our growth strategy

s or at all, sll uccessfullyll
businesse
ii
tt

future acquisitions
ll nii

esult i

s and losses or otherwise hinder

ff

ll

ii

ll

terms. Our ability t

As part of our growth strategy, including our desire to grow our retail platform, we may pursue acquisitions of assets or
operating entities. This strategy depends on the Company's ability to successfully identify and evaluate acquisition
o continue to implement this component of our
opportunities and consummate acquisitions on favorablea
growth strategy will be limited by our ability to identify appropriate acquisition or joint venturet
candidates and our financial
resources, including available cash and access to capita
In addition, the Company will compete with other companies for
these limited acquisition opportunities, which may increase the Company's cost of making acquisitions or limit the Company’s
ability to make acquisitions at all. 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 fromff
any future acquisitions or
joint ventures we may pursue.
In addition, the process of integrating acquired operations into our existing operations may
involve unknown risks, result in unforeseen operating difficulties and expenses, and may require significff ant financial resources
If the Company is unable to identify and
that would otherwise be available for the execution of our business strategy.
consummate futff uret

acquisitions, it may impede the Company's ability to execute its growth strategy.

al.

t

28

Our abilitll y t
renewablesll

chieve thett
o att
ll
developme

expected growth of our Vistrii
tt
ubstanti
is subject to stt

a ZerZZ o portfolio,
altt
ali

capita

requirements and other significant uncertaitt nti

of our solar generation, ESS,SS
es.

consistingii

nt projects,tt

tt

ii

ll

and other

ff

a

investments in renewablea

We have a substantial capita

al allocation plan intended forff

assets, emerging technologies and related projects. Notably,

assets, including solar development
projects and ESSs. As part of our business strategy, we plan to continually assess potential strategic acquisitions or investments
in renewablea
the Company's ability to successfully develop our
current renewables projects, or in the future acquire additional renewable assets, may be impacted by the demand for and
ity of renewable assets generally, which may vary depending on availability of projects and financing, as well as public
viabila
policy, financial and tax mechanisms implemented at the state and fede
ral levels to support the development of renewable
assets. Various factors could result in increased costs or result in delays or cancellation of our current or future renewabla e
projects, or the loss of, or declines in the value of, our investments in projects including, but not limited to, risks relating to
siting, financing, engineering and construction, permitting, interconnection requests, federal and state regulatory approvals, new
legislation or regulatory changes impacting the industry, commissioning delays, import tariffs, changes to federal income tax
laws, economic events or factors, environmental and community concerns, availability of or requirements forff
additional
funding, enhanced competition, or the potential for termination of the power sales contract as a result of a failure to meet certain
milestones. Further, the recent proliferation of renewable projects has resulted in a large volume of interconnection requests
submitted to grid operators, including the markets in which we operate, resulting in significant delays to the approval process
and estimated completion dates for our projects and others. Additionally, the increased demand for construction of renewables
projects, such as ESSs and solar projects, and other labor market and supply chain constraints have resulted, and may continue
to result, in limited availability of qualified specialists, contractors, and necessary services or materials, leading to delays in and
higher costs for the development and construction of our current and future planned projects. Should any of these factors occur,
our financial position, results of operations, and cash flows could be adversely affected, or our future growth opportunities may
not be realized as anticipated.

While certain of our subsidiaries are in various stages of developing and constructing solar generation facilities and ESSs
and certain of these projects have signed long-term contracts or made similar arrangements forff
the sale of electricity, in other
cases, our subsidiaries may enter into obligations in the development process even though the subsidiaries have not yet secured
power purchase arrangements or other important elements forff
a successful project. If the project does not proceed as planned,
our subsidiaries may remain obligated for certain liabilities even though the project will not be completed. Development is
inherently uncertain and we may forgo
certain development opportunities and we may undertake significant development costs
before determining that we will not proceed with a particular project. We believe that capitalized costs for projects under
development are recoverablea
; however, there can be no assurance that any individual project will be completed and reach
commercial operation. If these development efforts are not successful, we may abandon a project under development and write
off the costs incurred in connection with such project and could incur additional losses associated with any related contingent
liabilities.

ff

Circums

i

tances associatedtt withii

potentialii

divestitures could all

dversely affect our results of operations

tt

ii
and financ

ial conditiii on.

In evaluating our business and the strategic fitff of our various assets, we may determine to sell one or more of such assets.
ty in finding a buyer willing to purchase the asset at an
In addition, a prospective buyer may have diffiff culty

Despite a decision to divest an asset, we may encounter difficul
acceptable price and on acceptablea
obtaining financing. Divestitures

terms and in a timely manner.
could involve additional risks, including:

ff

t

diffiff culties 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.

t

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

which could adversely affecff

t our results of operations and financial condition.

29

If our goodwillii , ill nt
tt
earninrr

gs.n

ii angibl

e all

ssets, or long-livll ed assets become impaire

m

d, we may be required to record a significant charger

to

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 forff
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
. 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.

value of the asset may not be recoverablea

rr

We performff

ed our annual assessment of goodwill and non-amortizing intangibles in the fourth quarter of 2021 and
determined that no material 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
an ownership cii
attribute

tt

tt

s and our federal net operati

o

hange as definedii

of our common stock, or sales or dispositiii ons of our common stock by stockhokk
tt

Revenue Code (IRC) §382 could further

ur abilitll y t

ii
limi

ldersdd
o utt

t oii

tt
, ts hat
se certaintt

result i

ll nii
tax

tt

tt
in Internal
ii
losses to offset our future taxable i

ngii

.ee
ll ncome

ff

If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs that could be
used in any one year foll
owing 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
its merger with Dynegy; however, Vistra's use of such attributes is limited
outside our control. Vistra acquired NOLs fromff
under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy.
If there is an "ownership
change" with respect to Vistra (including by the normal trading activity of greater than 5% stockholders), the utilization of all
a provided under IRC §382
NOLs existing at that time would be subject to additional annual limitations based upon a formul
that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership change.
In
addition, any ownership change with respect to Vistra could result in additional limitations on our ability to use certain tax
attributes, including depreciation, existing at the time of any such ownership change and have an impact on our tax liabia lities
and on our obligations under the TRA.RR

ff

Tax legislat
iontt
e
increased taxesaa

initiii ati
ii
or fees, could have a material

ves or challenges
tt

ll

to our tax positions, or potential future legise

adverse effect on our financial condition,

tt

on of new or
lation or the impositi
ff
resultsll of operations and cash flows.

m

We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time,
legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes.
There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative
measures. The Tax Cuts and Jobs Act of 2017 (TCJA), enacted December 22, 2017, introduced significant changes to current
U.S. federal tax law. These changes are complex and continue to be the subject of additional guidance issued by the U.S.
Treasury and the Internal Revenue Service.
In addition, the reaction to the federal tax changes by the individual states
continues to evolve. Our interpretations and assumptim ons around U.S. tax reform may evolve in future periods as further
administrative guidance and regulations are issued, which may materially affecff

tive tax rate or tax payments.

t our effecff

U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There
can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there
could be a material impact on our results of operations and financial condition.

Additionally, U.S. federal income tax reform and changes in other tax laws could adversely affect us. For example,
President Biden has set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws.
Such proposals include, but are not limited to (i) an increase in the U.S. corporate income tax rate and (ii) implementation of a
15% minimum tax on a corporation’s worldwide book income. Congress could consider some or all of these proposals in
connection with tax reform to be undertaken by the Biden administration. It is unclear whether these or similar changes will be
enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets
may impose new or increased taxes or fees on various aspects of our operations. The passage of any legislation as a result of
these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees
could have a material adverse effect on our financial condition, results of operations and cash flows.

30

We are required to pay the holders of TRA Rightgg s ftt orff

ii
certaitt n t

axtt

i
benefite s,tt which amounts could be substanti
al.

tt

On the Effective Date, we entered into the TRA wRR

ith American Stock Transfer & Trust Company, LLC, as the transfer
agent. Pursuant to the TRARR , we issued beneficial interests in the rights to receive payments under the TRA (RR 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 $395 million as of
December 31, 2021 related to these future payment obligations (see Note 8 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 cRR

ould be materially different than this estimate.

ff

ttributablea

The TRA gRR

enerally provides forff

ights of 85% of the amount of cash savings, if
the payment by us to the holders of TRA RRR
lly realize as a result of our use of (a) the tax
any, in U.S. federal, state and local income tax that we and our subsidiaries actuat
basis step up au
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
plus interest
(c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA,RR
ill vary
r
accruing
tors, including the amount and timing of the taxable income we generate in the future and the
depending upon a number of facff
ng imputed interest.
tax rate then applicablea

, our use of loss carryovers and the portion of our payments under the TRA cRR

tax return. The amount and timing of any payments under the TRA wRR

from the due date of the applicablea

t
onstituti

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,RR recipients of the payments under the TRA wRR
ill 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 could make payments under the TRA tRR hat
are greater than its actual cash tax savings. Any amount of excess payment can be used to reduce future
ayments, but
cannot be immediately recouped, which could adversely affect our liquidity.

TRA pRR

ff

s
Because Vistra is a holding company with no operations of its own, its abia lity to make payments under the TRA iRR
dependent on the ability of its subsidiaries to make distributions to it. To the extent that Vistra is unable to make payments
under the TRA bRR
ecause 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 in periods in which such payments are made.

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

ii
ermi
nation
tt
We may be required to make an early t

ll

payment to the holders of TRA Righi

ts under thett

TRA.RR

The TRA pRR

rovides that, in the event that Vistra breaches any of its material obligations under the TRARR , or upon

certain
of business combination or certain other changes of control, the transfer agent under the
ay treat such event as an early termination of the TRARR , in which case Vistra would be required to make an immediate
ights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points)

u

mergers, asset sales, or other forms
TRA mRR
payment to the holders of the TRA RRR
ff
of the anticipated future

ff

tax benefits based on certain valuation assumptim ons.

u

As a result, upon

any such breach or change of control, we could be required to make a lump sum payment under the TRARR
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 liabia lity for payments

made under the TRA sRR

et forth in our financial statements, which could have a substantial negative impact on our liquidity.

31

Regulatory and Legislative Risks

ii

Our busines
may in the futff ure adversely impactm

ses are subject to ongoing cn

omplem x gee
ii

overnmentaltt

and legisl
ati
ll
e
ii
financ
y,tt
i
ses, resultsll of operations, liqui
dit

regulations
tt
i

on that have adversely impactm
tt
ed,
s.w
and cash flowff

ial conditiontt

, ott ur busines

and

r

gas, carbon

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory
ing of the energy industry, including competition in power generation and sale of electricity,
initiatives regarding the restructurt
energy certificates, and other commodities. Although we attempt to comply with
t
natural
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. Compliance with, or changes to, the requirements under these legal and regulatory regimes, including those
proposed or implemented under the Biden administration, may cause the Company may adversely impact our businesses,
results of operations, liquidity, financial condition and cash flows.

offsets and renewablea

Our businesses are subject to numerous state and federal laws (including, but not limited to, PURA,RR the Federal Power
Act, the Natural Gas Policy Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act
(CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act (RCRA), the Energy Policy Act of 2005,
the Dodd-Frank Wall Street Reformff
and the Consumer Protection Act and the Telephone Consumer Protection Act), changing
governmental policy and regulatory actions (including those of the FERC, the NERC, the RCT, the MSHA, the EPA, the NRC,
the DOJ, the FTC, the 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
and design, operation of nuclear generation facilities, construction and operation of other
not limited to, market structuret
generation facilities, development, operation and reclamation of
recovery of costs and investments,
lignite mines,
decommissioning costs, market behavior rules, present or prospective wholesale and retail competition, administrative pricing
ity standards and
mechanisms (and adjustments thereto),
environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market
s and regulations. Additionally, Ambit’s direct selling business (i) could be found
behavior and other competition-related ruler
by federal, state or foreff
icable law or regulations, which may lead to our inability
to obtain or maintain a license, permit, or similar certification and (ii) may be required to alter its compensation practices in
order to comply with applicable fede
ral or state law or regulations. Changes in, revisions to, or reinterpretations of, existing
laws and regulations may have a material adverse effect on our businesses, results of operations, liquidity, financial condition
and cash flows.

rates for wholesale sales of electricity, mandatory reliabila

ign regulators not to be in compliance with appl

a

ff

ff

Extreme weather events have resulted, and in the future may result, in efforts by both federal and state government and
regulatory agencies to investigate and determine the causes of such events. For example, as a result of Winter Storm Uri, we
received a civil investigative demand from the Attorney General of Texas as well as a request for information from ERCOT,
NERC, and other regulatory bodies related to this event and may receive additional inquiries. Such efforts have resulted, and in
the future may result, in changes in laws or regulations that impact our industry and businesses including, but not limited to,
chain including generation, transmission,
additional requirements for winterization of various facets of the electricity supply
and fuel supply; improvements in coordination among the various participants in the electricity supply
chain during any future
event; restrictions or limitations on the types of plans permitted to be offered to customers; potential revisions to method or
calculation of market compensation and incentives relating to the continued operation of assets that only run periodically,
including during extreme weather events or other times of scarcity; and other potential legislative and regulatory corrective
actions that may be taken. Previously announced or future legal proceedings, regulatory actions, investigations, or other
ngs of
administrative proceedings involving market participants may result lead to adverse determinations or other findi
violations of laws, rules or regulations, any of which may impact the ability of market participants to satisfy, in whole or in part,
their respective obligations. We are continuing to monitor and evaluate the impacts of this developing situation but at this time
we cannot estimate the likelihood or impacts of any legislative or regulatory changes or actions (including enforcement actions
that may be brought against various market participants) that may occur as a result of the event on our business, financial
condition, results of operations, or cash flows.

u

u

ff

32

generation. For example, changes to, or development of, legislation that requires the use of clean renewablea

Finally, the regulatory environment has undergone significant changes in the last several years due to state and federal
the addition of large amounts of new
policies affecting wholesale and retail competition and the creation of incentives forff
and
renewablea
sources or mandate the implementation of energy conservation programs that require the implementation of new
ff
alternate fuel
technologies, could increase our capita
al expenditures and/or impact our financial condition. Additionally, in some retail energy
markets, state legislators, government agencies and other interested parties have made proposals to change the use of market-
based pricing, re-regulate areas of these markets that have previously been competitive, or permit electricity delivery crr
ompanies
ilities. Other proposals to re-regulate the retail energy industry may be made, and
to construct or acquire generating facff
gas deregulation or restructuring process may be delayed,
legislative or other actions affecting electricity and natural
discontinued or reversed in states in which we currently operate or may in the future operate.
If such changes were to be
enacted by a regulatory body, we may lose customers, incur higher costs and/or find it more difficult to acquire new customers.
t that
These changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effecff
the changing regulatory environment will have on our business.

t

We are requiredii

tt
to obtain,

and to complym with,tt

rr
governmen

rr
t permit

s att

nd 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
shment of conditions that make the project or activity forff which the permit or license was sought
sometimes result in the establia
to denial, revocation or
unprofitable or otherwise unattractive.
modification under various circumstances. Failure to obtain or comply with the conditions of permits or licenses, or failure to
comply with applicable laws 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 l
aws and regulations or permit conditions, (c) local community, political or other
opposition and (d) executive, legislative or regulatory action.

In addition, such permits or licenses may be subject

t

Our inabila

ity 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 activities at our facilities to need to be changed to
avoid violating applicable laws and regulations or elicit claims that historical activities at our facilities violated appli
laws
In addition to the possible imposition of fines in the case of any such violations, we may be required to
and regulations.
undertake significant capita
al investments and obtain additional operating permits or licenses, which could have a material
adverse effecff

t on us.

cablea

a

Our cost of co

ii
omplim ance

withii

existingii

and new environmii

ental laws could hll

ave a material adverse effect on us.

We are subject

to extensive environmental regulation by governmental authorities,

including federal and state
environmental agencies and/or attorneys general. We may incur significant additional costs beyond those currently
contemplated to comply with these regulatory requirements. If we fail to comply with these regulatory requirements, we could
be subject to administrative, civil or criminal liabia lities and fines. Existing environmental regulations could be revised or
reinterpreted, new laws and regulations could be adopted or become applicablea
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 foreff

going could have a material adverse effect

on us.

ff

The EPA has recently finaff

lized 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
t our existing generation facilities or our ability to cost-effectively develop
additional regulatory actions that may adversely affecff
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, such as the EPA's proposed Cross-State Air Pollution Rule Update, the ACE rulerr
and any
, and actions under the Regional Haze program, could require us to install
proposed or future actions to replace the ACE ruler
significant additional control equipment, resulting in potentially material costs of compliance forff
our generation units, including
capita
al expenditures, higher operating and fuel costs and potential production curtailments. These costs could have a material
adverse effect on us.

33

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 approva
l 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.

a

In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that
we have acquired, leased, developed or sold, 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 certain environmental liabia lities. Another party could, depending on the circumstances, assert an environmental claim
against us or fail to meet its indemnification obligations to us, which could have a material adverse effecff

t on us.

We could bll
climll
are subject to l

e material
tt
ate change that could r
awll

suiw tsii

equireii
for allell gede

tt

ll

lyll and adversely affected ifi new federal or state legislati

ll

on or regulati

ll

efforts t
tt
tt hat
damage to persons or property resultill ngii

exceed or are more expensive than our currently planned initiati

from greenhouse gas emissi

ii

ons.

ons are adopted to att
ii

ddress global
ves or ifi we

a

de), a tax on carbon or GHG emissions,

There is attention and interest 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 several
proposals intended to address climate change using different approaches, including a cap on carbon emissions with emitters
the
allowed to trade unused emission allowances (cap-and-tra
development of low-carbon technology and federal renewabla e portfolio standards. In July 2019, the EPA finalized the ACE rulerr
that developed emissions guidelines that states must use when developing plans to regulate GHG emissions from existing coal-
was vacated by the D.C. Circuit Court and remanded to the EPA
fueled electric generating units. In January 2021, the ACE rulerr
for further consideration in accordance with the court’s ruling. The D.C. Circuit’s decision has been appea
led to the U.S.
February 2022. The EPA may develop a more stringent and more
Supreme Court and oral argument is scheduled forff
in its remand proceeding and has been directed by the Biden Administration to
encompassing rule to replace the ACE ruler
review this rule and others promulgated by the EPA during the Trump Administration. Prior to the vacaturt
and remand, states
where we operate coal plants (Texas, Illinois and Ohio) had begun the development of their state plans to comply with the now-
in recent years asserting damage claims related
ral court cases have been filedff
vacated ACE ruler
to GHG emissions, and the results in those proceedings could establia
sh 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 that could require efforts that exceed or are more
expensive than our currently planned initiatives or if we are subject to lawsuits for alleged damage to persons or property
resulting from GHG emissions.

. In addition, a number of fede

incentives forff

a

ff

Additionally, in January 2021, President Biden issued written notification to the United Nations of the U.S.'s intention to
rejoin the Paris Agreement, effective in February 2021. Although the Paris Agreement does not create any binding obligations
for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future
emissions, and various
corporations, investors and U.S. states and local governments have previously pledged to further the goals of the Paris
Agreement. Additionally, the Biden Administration has directed certain agencies to submit a plan to the National Climate Task
ution-free electricity sector by 2035. The Company's plan to transition to clean power generation
Force to achieve a carbon-poll
sources and reduce its GHG emissions may not be completed in this timeframe
and we may not otherwise achieve our
ff
sustainability and emissions reduction targets as expected. Accordingly, we may be required to accelerate or change our
targets, incur additional expenses, and/or adjust or cease certain operations as a result of newly implemented fede
ral and/or state
regulations to reduce future carbon emissions.

r

ff

ff

ii
Luminant's

mining

ii

operations are subject to Rtt

CT oversight.

i

We currently own and operate, or are in the process of reclaiming, various 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, multiple 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 rulerr
s and regulations and whether it has met all the requirements
of its mining permits in Texas. 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.

34

Luminant's l
'
are reclaimll

e mtt

igll nitgg
ed over the next several years.rr

ining reclamat

iontt

ll

activtt

ity wtt

ill rll

equire signigg fica

i

nt resources as exiee sti

ii ngii

and retireii d mining operations

In conjunction with Luminant's announcements in 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 generation asset, 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 is projected to spend approximately $265 million (on a
nominal basis) to achieve its reclamation objectives.

Litiii gati
i
i
liabil

e
on, legal

proceedings, rs

itll iett s and reputational

tt

egulatll orytt
damage that could hll

i
investigati
ave a materi

tt

ali

adverse effect on us.

ons or other adminis

ii

trativtt e proceedings could expose us to s

tt

ignificant

We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment,
injuries and damages. We evaluate litigation claims and legal
commercial, and environmental issues, and other claims forff
proceedings to assess the likelihood of unfavorablea
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 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 fromff
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 filff ed 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 effecff

t on us.

ii

Our retail bii usinesse
statett
profitabiliii tyii of our business.

hich we operate, ae

s in wii

ii

s, which each have REP cEE

re subject to ctt

ertificaff
hangingii

tions that are subject to r
state rules and regulati

eview of the public utilityii
tt

ons that could have a material

commissions in the
on the
impactm

tt

ll

t

The competitiveness of our U.S. 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
n, including financial requirements, can affect the competitiveness of our retail businesses. Any removal or
REP certificatio
revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail
customers in the applicablea
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.

rr

ff

35

Operational Risks

power supply costs and demand for power have and could in the future adversely affect thett

leii

VolVV ati
ll
of our retail bii usinesses.

e
financial performanc

r

Although we are the primary provider of our retail businesses' wholesale electricity supply requirements, our retail
businesses purchase a portion of their supply requirements fromff
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 refleff cted in the rates charged to customers due to, among other facff

tors:

u

•
•
•
•
•
•

supply procurement contracts used and the timing of entering into related contracts;

varying
rr
subsequent changes in the overall price of natural
daily, monthly or seasonal fluctuations in the price of naturat
transmission constraints and the Company's ability to move power to our customers;
out-of-market payments, uplifts, or other non-pass through charges, and
changes in market heat rate.

l gas relative to the 12-month forwa

gas;

ff

t

rd prices;

The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers'
tors,
transmission and distribution outages, demand-side management programs, competition and economic

actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other facff
weather events,
conditions, such as Winter Storm Uri in February 2021.

ons are subject to significff ant competm ittt iontt
perati
Our retail oii
o
ii
nd the inabi
customers arr

t new customers.

tt
to attrac

liii tyii

from other REPsRR

, ws

hich could r

ll

ii
esult i

ll
ll n a l

oss

gn
of existinii

We operate in a very competitive retail market and, as a result, our retail operation faces significant competition for
customers. We believe our brands are viewed favora
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 fromff
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.

blya

ff

In addition to competition from the incumbent REP, we may face competition fromff

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.
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 profitablea

for us to competm e in these markets.

36

Our retail oii
elecll
tricityii
ii
satisfac

ations rely on the infrastruc
pero
mat
rr
nfor
ii
to, and to obtain i
tt

tion and could have a material

iontt

ii

adverse effect on us.

tt
ture of lo ocll al utiliii tiii es or indepenee
about, our customers. Any infrastruc

dent trantt
ture fail

tt

ii
smissi

on systeyy m opero

ff ure could negatively impactm

ators to provide
r
tt
custome

a

The substantial majoa rity of our retail operations depend on transmission and distribution facilities owned and operated by
ity is inadequate, our ability to
unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capac
o sales or buy more expensive wholesale electricity than is
sell and deliver electricity may be hindered and we may have to forgff
ity-constrained area or, with respect to capacity performance in PJM and performance incentives in ISO-
available in the capac
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 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,
failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer
any infrastructuret
satisfaction with our service. Any of the foregoing could have a material adverse effect on us.

a

The operation of our businesse
tt
our infrastruc
ll
regulatory

action, and disrupt business

ture that breach cyber/data

rr

ii

ii

s is sii ubject to att

dvanced persistenii

t cybc

er-based security threats and integrity

e

security measures could expose us to significff ant liabil

itll iett s, reputati

ii

operations, which could have a material

tt

adverse effect on us.

risk. Attacks okk
tt

n
onal damage,e

Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliablea

storage,
processing and communication of electronic data and the use of sophisticated computer hardware and software systems and
much of our information technology infrastructuret
is connected (directly or indirectly) to the internet. Our information
technology systems and infrastructure,
and those of our vendors and suppliers, are susceptible to threats which could
compromise confidentiality, integrity or availability. While we have controls in place designed to protect our infrastructure,
such breaches and threats are becoming increasingly sophisticated and complex, requiring continuing evolution of our program.
could disrupt normal
Any such breach, disruption or similar event that impairs our information technology infrastructuret
business operations and affect our ability to control our generation assets, maintain confidentiality, availability and integrity of
our restricted data, access retail customer information and limit communication with third parties, which could have a material
adverse effecff

t on us.

t

t

As part of the continuing development of new and modified reliabila

Critical Infrastructure Protection reliabila
assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up tu
failure to comply with mandatory electric reliabila
disruptions from cyber/data and physical security breaches.

ity standards, the FERC has approved changes to its
ity standards and has established standards for assets identified as "critical cyber
o $1 million per day, per violation) for
ity standards, including standards to protect the power system against potential

Further, our retail business requires us to access, collect, store and transmit sensitive customer data in the ordinary course
of business. Concerns about data privacy have led to increased regulation and other actions that could impact our businesses
and changes in data privacy and data protection laws and regulations or any failure to comply with such laws and regulations
could adversely affect our business and financial results. 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.

37

Although we take precautions to protect our infrastructure, we have been, and will likely continue to be, subject to
attempts at phishing and other cybersecurity intrusions. International conflict increases the risk of state-sponsored cyber threats
and escalated use of cybercriminal and cyber-espionage activities.
In particular, the current geopolitical climate has further
escalated cybersecurity risk, with various government agencies, including the U.S. Cybersecurity & Infrastructure Security
Agency, issuing warnings of increased cyber threats, particularly for U.S. critical infrastructure.
While the Company has not
experienced a cyber/data event causing any material operational, reputational or finaff
ncial impact, we recognize the growing
threat within the general marketplat
ce and our industry, and there is no assurance that we will be able to prevent any such
If a material breach of our information technology systems were to occur, the critical operational
impacts in the future.
capabi
lities and reputation of our business may be adversely affected, customer confidence may be diminished, and our
a
business may be subject to substantial legal or regulatory scrutiny and claims, any of which may contribute to potential legal or
regulatory actions against the Company, loss of customers and otherwise have a material adverse effect on us. Any loss or
our generation, commercial or retail operations, loss of customers, or
disruption of critical operational capabi
loss of confidential or proprietary data through a breach, unauthorized access, disruption, misuse or disclosure 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.
al and operating costs to
We cannot provide any assurance that such events
implement increased security for our information technology infrastructure.
and impacts will not be material in the future, and our efforts to deter, identify and mitigate future
breaches may require
additional significant capia tal and may not be successful.

In addition, we may experience increased capita

lities to support

u

a

ff

t

t

We may suffer material
arisingii

tt
from the ownership aii

losses, costs and liabil
nd operationtt

i
CC
of the Comanch

e PeakPP

.yy
nuclear generation faciliii tyii

itll iett s due to operation risks, regulatorytt

risks, as nd the risk ofo nuclear accidents

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:

•

•
•
•

•
•
•
•
•
•

t

, cybersecurity, insider threat,

unscheduled outages or unexpected costs due to equipment, mechanical, structural
third-party compromise or other problems;
inadequacy or lapses in maintenance protocols;
the impairment of reactor operation and safety systems dued
the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive
materials;
the costs of procuring nuclear fuel;
the costs of storing and maintaining spent nuclear fuel
terrorist or cybersecurity attacks and the cost to protect against any such attack;
the impact of a naturat
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.

at our on-site dry cask storage facility;

to human error or force majea ure;

l disaster;

ff

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 folff

lowing are among the more significant related risks:

•

•

Operational Riskii — Operations at any generation facility could degrade to the point where the facility would have to
If such degradations were to occur at the Comanche Peak Facility, the process of identifying and
be shut down.
the facility to operation could require significant time and
correcting the causes of the operational downgrade to returnt
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.
Regulat
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 capita
al expenditures or result
in increased operating or decommissioning costs.

ory Riskii — The NRC may modify, suspend or revoke licenses and impose civil penalties forff

e

38

•

Nuclear Accidendd t Risk — Although the safety record of the Comanche Peak Facility and other nuclear generation
facilities 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 mainten
involvell

ii
ii
ant risks

significi

ance of power generation facff

ilities and relatedtt mining

ii

that could adversely affect our resultsll of operations, liquidi

i

operations are capitaltt
tyii and financial condition.

tt

intensive and

t

a

al to maintain the facff

The operation and maintenance of power generation facilities and related mining operations involve many risks,
, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of
including, as applicablea
ilities, the dependence on a specific fuel source, the inability to transport our product to our
sufficient capita
ity or the impact of unusual or adverse weather
customers in an efficient manner due to the lack of transmission capac
events, or terrorist attacks, as well as the risk of performance below expected levels of output,
conditions or other natural
efficiency or reliabila
ity, 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 capita
al expenditures to operate at peak
al expenditures arises from (a) increased starting and
ity. The risk of increased maintenance and capita
efficiency or reliabila
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
disasters, wars, terrorist or cyber/data security acts, including nation-state attacks or organized
facilities dued
cyber 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.

to storms, natural

t

t

al expenditures that will be required dued

We cannot be certain of the level of capita

to changing environmental and safetyt
laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected
disasters or terrorist or cyber/data security attacks). The unexpected
events (such as environmental
requirement of large capita
al 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
capita

impacts, natural

al expenditures.

t

t

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
If we do not have adequate
procure replacement power at spot market prices in order to fulfill contractual
commitments.
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
al expenditures and costs, and generate
us. Further, our inabila
earnings and cash flows 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 fromff
vendors and obligate contractors to
meet certain performanc
e 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.

ity to operate our generation facilities efficiently, manage capita

ff

t

39

Operation of power generation faciliii tiii es involvell
have a matertt
these risks and hazards. Our employm
due to the nature of our operations.

ees, contractors,

tt

ial adverse effect on our revenues and resultsll of operations, and we may not have adequate insurance to ctt

s significant risks and hazards customary to the power induii

could
over
rs and the general public may be exposed to a risk of injury

tt
stry tr hat

tt
custome

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large
pieces of equipment and delivering electricity to transmission and distribution systems.
risks such as
extreme weather, earthquake, flood, lightning, hurricane and wind, other human-made hazards, such as nuclear accidents, dam
failure, gas or other explosions, mine area collapses,
collapse, machinery failure and other dangerous incidents
t
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.

In addition to natural

fire, structural

a

t

ff

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 dt
amage 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 sufficien
t 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 A successful claim forff 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, including increasing pressure
on firms that provide insurance to companies that own and operate fossil fuel
generation, 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.

ff

We may be material
tt
ii
requireme
e
legal
to CCR.CC
relatingtt

lyll

and adversely affected by ob

i
bligati

nts that govern the operations, assessments, ss

ons to complym
torage, ce

federadd

withii
losure, ce

l and state regue

orrectivtt e action,

tt

, as nd other
lations, ls aws
tt
disposal and monitoring

ll

As a result of electricity produced forff

decades at coal-fueled power plants in Illinois, Texas and Ohio, we manage large
amounts of CCR material in surface impoundments, all in compliance with applicable regulatory requirements. In addition to
the federal requirements under the CCR rulrr e, CCR surfaceff
impoundments will continue to be regulated by existing state laws,
regulations and permits, as well as additional legal requirements that may be imposed in the future. These federal and state
laws, regulations and other legal requirements may require or result in additional expenditures, increased operating and
maintenance costs and/or result in closure of certain power generating facilities, which could affect the results of operations,
financial position and cash flows of the Company. We have recognized ARO related to these CCR-related requirements. As
the closure and CCR management work progresses and final closure plans and corrective action measures are developed and
approved at each site, the scope and complexity of work and the amount of CCR material could be greater than current
estimates and could, therefore, materially impact earnings through increased compliance expenditures.

t

40

The EPA has been directed by the Biden Administration to review a number of environmental ruler

s adopted by the EPA
during the Trump Administration, including Coal Combustion Residuals (CCR) rule, the Emissions Limitation Guidelines
(ELG) rule, the Affordable Clean Energy (ACE) rule and the PM and Ozone National Ambient Air Quality Standards
(NAAQS) rules. All of these rules may significantly and adversely impact our existing coal fleff et and may lead to accelerated
plant closure timefraff mes. In addition, the expected revisions to the ACE rulerr
and NAAQS also have the potential to adversely
impact our gas-fired units.

The EPA is reviewing applications submitted by us to extend closure deadlines for many of our CCR impoundments.
The scope and cost of that closure work could increase significantly based on new requirements imposed by the EPA or state
agencies. There is no assurance that our current assumptim ons for closure activities will be accepted by EPA. If ponds must be
closed sooner than anticipated, plant closures timeframes may be accelerated.

The availabil

itll y att

ll

nd cost of eo missi

ii

on allowances could adversely impactm

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 force
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 forff
purchase, but only at significantly higher prices, the purchase of such allowances could
materially increase our costs of operations in the affected markets.

d to purchase such allowances on the open market, which could be costly.

ff

We may be materially all

nd adversely affected by tb hett

effects ott

f eo

xtree

eme weather

tt

conditions and seasonalitll y.tt

We may be materially affecff

ted by weather conditions and our businesses may fluctuat

e substantially on a seasonal basis as
the weather changes. In addition, we are subject to the effects of extreme weather conditions, including sustained or extreme
disasters, which could stress
t
cold or hot temperatures,
ity, limit our ability to procure adequate fuel supply, or result in outages, damage or
our generation facilities and grid reliabila
destroy our assets and result in casualty l
osses that are not ultimately offset by insurance proceeds, and could require increased
capita

or maintenance costs, including supply chain costs.

hurricanes, floods, droughts, storms, fireff

s, earthquakes or other natural

al expenditures

t

t

t

t

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, certain
extreme weather events have previously affected, and may in the future, affect, the availabila
ity of generation and transmission
ity, limiting our ability to source or deliver power where it is needed or limit our ability to source fuel for our plants,
a
capac
including due to damage to rail or natural
Additionally, extreme weather has resulted, and may in
t
the future result, in (i) 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, (ii) the failure of equipment at our generation
gas, diesel and coal, or
facilities, (iii) a decrease in the availabila
(iv) unpredictable curtailment of customer load by the applicablea
ISO/RTO in order to maintain grid reliability, resulting in the
realization of lower wholesale prices or retail customer sales. For example, Winter Storm Uri in February 2021 had a material
impact on our results of operations.

ity of, or increases in the cost of, fuel sources, including natural

gas pipeline infrastructure.

t

t

Additionally, climate change may produce changes in weather or other environmental conditions, including temperature
In addition, the potential physical effects of
and other climatic events, could disrupt our

or precipitation levels, and thus may impact consumer demand for electricity.
climate change, such as increased frequency and severity of storms, floods,
operations and cause us to incur significant costs to prepare forff

or respond to these effecff

ts.

ff

Weather conditions, which cannot be reliablya

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,
as well as significantly limiting the supply of, or increasing the cost of our fuel supply, each of which could have a material
adverse effect on our business, results of operations, financial condition and liquidity.

41

The outbreak of COVID-19,
matertt

ial and adverserr

effect on our business,

or the future outbreak of any other highly infectious
ial condition,

and results ott

tt
pero

ii
financ

f oo

II

ii

tt

ations.

or contagious diseases, could have a

The outbreak of the COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, and we
are responding to the outbreak by taking steps to mitigate the potential risks to us posed by its spread. We continue to examine
the impacts of the pandemic on our workforce, liquidity, reliabila
ity, cybersecurity, customers, suppliers, along with other
macroeconomic conditions and cannot currently predict whether COVID-19 will have a material impact on our results of
operations, financial condition, and cash flows. Additionally, global recovery and transition from COVID-19 could have a
material impact on supply, business and commodity market funda

mentals on a national and global scale.

ff

Because we are deemed a critical infrastructuret

provider that provides a critical service to our customers, we must keep
our employees who operate our businesses safe and minimize unnecessary risk of exposure. We have updated and
implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic. This plan guides our
emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public.
We will continue to monitor developments affecting both our workforce and our customers, and we will take additional
precautions that we determine are necessary in order to mitigate the impacts. In particular, we have taken extra precautions for
our employees who work in the field and for employees who continue to work in our facilities including requiring, for both
employees and contractors, social distancing where possible and requiring the use of appropriate personal protective equipment
in certain circumstances. We have implemented work-from-home policies and other safety measures where appropriate,
testing at
including, but not limited to, encouraging vaccinations and boosters, answering screening questions and temperaturet
all of our locations for unvaccinated employees, contractors, and other essential visitors and closing our facilities to non-
essential visitors. While our systems and operations remain vulnerable to cyber-attacks and other disruptions due in part to the
fact that a portion of our workforce continues to work remotely, we have implemented physical and cyber-security measures to
ensure that our systems remain funct
ional in order to both serve our operational needs with a remote workforce and keep them
running to ensure uninterrupted service to our customers. We will continue to review and modify our plans as conditions
change.

ff

Measures to control the spread of COVID-19, including restrictions on travel, public gatherings, and certain business
operations, have affected the demand for the products and services of many businesses in the areas in which we operate and
disrupted supply chains around the world. The full scope and extent of the impacts of COVID-19 on our operations are
unknown at this time. However, COVID-19 or another pandemic could have material and adverse effects on our results of
operations, financial condition and cash flows due to, among other facff
tors, a protracted slowdown of broad sectors of the
economy, changes in demand or supply for commodities, significant changes in legislation or regulatory policy to address the
pandemic (including prohibitions on certain marketing channels, moratoriums or conditions on disconnections or limits or
restrictions on late fees), reduced
d demand for electricity (particularly from commercial and industrial customers), increased late
or uncollectible customer payments, negative impacts on the health of our workforce, a deterioration of our ability to ensure
business continuity (including increased vulnerability to cyber and other information technology risks as a result of a significant
portion of our workforce continuing to work from home), and the inability of the Company's contractors, suppliers, and other
business partners to fulfill their contractual obligations.

Despite our efforts to manage these impacts to the Company, their ultimate impact also depends on factors beyond our
knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its
spread and mitigate its public health effecff
ts. To the extent COVID-19 adversely affects our business and financial results, it
may also have the effect of hastening, heightening, or increasing the negative impacts of, many of the other risks described in
this Risk Factors section.

42

Changes in technology,o
our generationtt

faciliii tiii es and may otherwise have a material

tt

adverse effect on us.

increased electritt cityii

conservation efforts, or energy sustainabi

liii tyii

tt

efforts mtt

ay reduce the value of

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, hydrogen, micro turbines, photovoltaic (solar) cells,
batteries and concentrated solar thermal devices, along with improvements in traditional technologies. Such technological
advances may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure,
to remain competitive, and have resulted, and are expected to continue to
and may require us to make significant expenditures
reduce the costs of power production or storage, which may result in the obsolescence of certain of our operating assets.
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 and our future success will depend, in part, on our ability to
to technological changes, to offer services and products that meet customer demands and
anticipate and successfully adapta
evolving industry standards. 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 or distributed 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 affecff

ted.

t

t

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 significan
t decrease in electricity demand as a result of such efforts
ff
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
al expenditures if we are required to
could have a material adverse effect on us. Furthermore, we may incur increased capita
increase investment
on energy
in conservation measures. Additionally,
sustainability efforts, including desire for, or incentives related to, the development, implementation and usage of low-carbon
technology, may result in decreased demand for the traditional generation technologies that we currently own and operate.

increased governmental and consumer focus

ff

We may potentiallyll
energyr

industrytt

be affected by eb merging tn

may over timtt
overall including distributed generation and clean tectt hnology.

ectt hnologie

tt
s that

ll

ll

a
e affec

t change in capacity mtt

arkets att

nd the

Some of these emerging technologies are shale gas production, distributed renewable energy technologies, energy
efficiency, broad consumer adoption of electric vehicles, distributed generation and energy storage devices. Additionally,
large-scale cryptocurrency mining is becoming increasingly prevalent in certain markets, including ERCOT, and many of these
cryptocurrency mining facilities are "behind-the-meter." Such emerging technologies could affect the price of energy, levels of
customer-owned generation, customer expectations and current business models and make portions of our electric system
power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. These emerging
ity of utility counterparties and could have significant impacts on wholesale
technologies may also affect the financial viabila
market prices, which could ultimately have a material adverse effect on our financial condition, results of operations and cash
flows could be materially adversely affecff

ted.

tt
The loss of the services of our key management and personnel could adversely affect our abilitll y t
ii
businesse

s.

tt

o s

uccessfullyll

operate our

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. Further, we are
facing an increasingly competitive market for hiring and retaining skilled employees in certain skill areas, which is exacerbated
by the effects of the COVID-19 pandemic and increased acceptance of hiring remote working employees by our competitors
and other companies. Difficul
ties in attracting and retaining highly qualified skilled employees may restrict our ability to
adequately support our business needs and/or result in increased personnel costs. In addition, effective succession planning is
important to our long-term success. Failure to timely and effectively ensure transfer of knowledge and smooth transitions
involving senior management and other key personnel could hinder our strategic planning and execution.

ff

43

We could be matertt

iallyll and adversely impactm

edtt

by strikes or work stoppages by our unionized emplm oye

ll

es.

t

gas- and nuclear-fueled generation operation, as well as some battery orr

As of December 31, 2021, we had approximately 1,400 employees covered by collective bargaining agreements. The
terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations,
lignite-, coal-, natural
perations, expire on various dates
between March 2022 and May 2024, but remain effective 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
strife or
or we could experience reduced power generation or
disruption, we would be responsible for procuring replacement labor
outages. We have in place strike contingency plans that address the procurement of replacement labor.
Strikes, work stoppages
or the inability to negotiate current or future collective bargaining agreements on favora
terms or at all could have a material
adverse effecff

a
of labor

t on us.

blea

a

a

ff

ff

Risks Related to Our Structure and Ownership of our Common Stock

a is a h
Vistrii
ii
ii
future liabil

oldingii
itll iett s of io tsii

subsidiaries.

companym

and its att

tt
bilitll y t

o ott

ff
btain f
unds
ii

from its stt ubsidiaries is structurallyll

subordinate

ii

ii
d tott existing

and

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

ff

tt

expectati

Evolvill ngii
mattett rs, and erosion of stakeholder trust
industry and could adversely affect our business,

tt
or confidence could influence actiott ns or decisions about our companym
ii

ons from stakeholders, including investors, on ESG issues, including climll

ial resultsll or stocktt

ff
operations, fs

inanc

price.

ate change and sustainabil

itll ytt
and our

tt

Companies across all industries are facing evolving expectations or increasing scrutiny from stakeholders related to their
nd stakeholder relations remain primary focus areas, and changing
approach to ESG matters. For Vistra, climate change, safety at
expectations of our practices and performance across these and other ESG areas may impose additional costs or create exposure
to new or additional risks. Our operations, projects and growth opportunities require us to have strong relationships with key
stakeholders, including local communities and other groups directly impacted by our activities, as well as governments and
investment funds and others which are
government agencies,
increasingly focused on ESG practices. Certain finff ancial institutions have announced policies to presently or in the future cease
investing or to divest investments in companies that derive any or a specified portion of their income from, or have any or a
specified portion of their operations in, fossil fuels.

investor advocacy groups, certain institutional

investors,

While we are strategically focused on successfully adaptia

ng to the energy transition and strongly committed to our ESG
practices and performance (including transparency and accountability thereof), our plans to transition to clean power generation
sources and reduce our carbon footprint may not be completed in the timefraff me and we may not achieve our targets as
expected, which could impact stakeholder trust and confidence. Any such erosion of stakeholder trust and confidence, evolving
expectations from stakeholders on such ESG issues, and such parties' resulting actions or decisions about our company and our
industry could have negative impacts on our business, operations, financial results, and stock price, including:

•

•

•
•
•
•
•
•

ff

ls;

negative stakeholder sentiment toward us and our industry, including concerns over environmental or sustainability
ral and state regulatory actions related thereto;
matters and potential changes in fede
loss of business or loss of market share, including to competitors who do not have any, or comparablea
operations involving fossil fueff
loss of ability to secure growth opportunit
the inability to, or increased difficulties and costs of, obtaining services, materials, or insurance from third parties;
reductd
delays in project
o
legal action;
l
inability or limitations on ability to receive applicable government subsidies, or competitors with smaller or no fossi
operations receiving subsidies forff which we are not eligible, or in larger amounts;

ions in our credit ratings or increased costs of, or limited access to, capital;

amounts, of

execution;

ies;

ff

t

44

•
•

•
•
•
•

increased regulatory oversight;
loss of ability to obtain and maintain necessary approvals and permits fromff
timely basis and on acceptable terms;
impediments on our ability to acquire or renew rights-of-wa
changing investor sentiment regarding investment in the power and utilities industry or our company;
restricted access to and cost of capia tal; and
loss of ability to hire and retain top talent.

ff

y or land rights on a timely basis and on acceptablea

terms;

governments and regulatory agencies on a

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 which we initiated 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.

ll
Holders

of our preferre

e

d stock may ha

ave interests att

nd rights that are different from our common stockholders.

We are permitted under our certificate of incorporation to issue up to 100,000,000 shares of preferred stock. We can issue
shares of our preferred stock in one or more series and can set the terms of the preferred stock without seeking any further
approval fromff
our common stockholders. Any preferred stock that we issue may rank ahead of our common stock in terms of
dividend priority or liquidation premiums and may have greater voting rights than our common stock, which could dilute the
value of our common stock to current stockholders and could adversely affect the market price of our common stock. As of
December 31, 2021, 1,000,000 shares of Series A Preferred Stock and 1,000,000 shares of Series B Preferred Stock were issued
and outstanding. The Preferred Stock represents a perpet
equity interest in the Company and, unlike our indebtedness, will
t
ual
not give rise to a claim for payment of a principal amount at a particular date; provided, the Company may redeem the Preferred
Stock at the specified times (or upon certain specified events) at the applicable redemption price set forth in the certificate of
designation of each of the Series A Preferred Stock and Series B Preferred Stock, respectively (Certificates of Designation).
The Preferred Stock is not convertible into or exchangeable forff
any other securities of the Company. Upon the liquidation,
dissolution or winding up of the Company, whether voluntary or involuntary, after payment or provision for payment of the
debts and other liabia lities of the Company, the holders of Preferred Stock will be entitled to receive, pro rata and in preference
to the holders of any other capia tal stock, an amount per share equal to $1,000 plus accrued and unpaid dividends thereon, if any.

rr

Unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A
Preferred Stock and the holders of at least two-thirds of the outstanding Series B Preferred Stock, voting as a separate class, we
of Designation) that
may not adopt any amendment to our certificate of incorporation (including the applicablea
would have a material adverse effect on the powers, preferences, duties, or special rights of such series of Preferredr
Stock,
subject to certain exceptions. In addition, unless we have received the affirmative vote or consent of the holders of at least two-
thirds of the outstanding Series A Preferred Stock and the holders of at least two-thirds of the outstanding Series B Preferred
Stock, voting as a class together with the holders of any parity securities upon which like voting rights have been conferred and
are exercisable, we may not: (i) create or issue any senior securities, (ii) create or issue any parity securities (including any
additional Preferred Stock) if the cumulative dividends payablea
on the outstanding Preferred Stock (or parity securities, if
applicable) are in arrears; (iii) create or issue any additional Preferred Stock or any parity securities with an aggregate
liquidation preference, together with the issued and outstanding Preferred Stock and any parity securities that are then
outstanding, of greater than $2.5 billion, and (iv) engage in any Transaction that results in a Covered Disposition (as such terms
are defined in the Certificates of Designation).

ff
Certificates

45

ff

In addition, holders of the Preferred Stock are entitled to receive, when, as, and if declared by our Board, semi-annual
initial issuance date of the Preferred Stock and
cash dividends on the Preferred Stock, which are cumulative from the applicablea
payablea
in arrears, and unless full cumulative dividends have been or contemporaneously are being paid or declared on the
Preferred Stock, we may not (i) declare or pay any dividends on any junior securities, including our common stock, or (ii)
redeem or repurchase any parity securities or junior securities, subject to limited exceptions set forth
in the Certificates of
Designation. There is no assurance that the Board will declare, or that we will pay, any dividends on our Preferred Stock in the
future. The holders of Preferred Stock (along with any parity securities then outstanding with similar rights) are entitled to elect
two additional directors in the event any dividends on Preferred Stock are in arrears for three or more semi-annual dividend
periods (whether or not consecutive), and such directors may have competing and different interests to those elected by our
common stockholders. The dividend rate forff
the Series A Preferred Stock from and including the initial issuance date of
October 15, 2021 until the first reset date of October 15, 2026 will be 8.0% per annum of the $1,000 liquidation preference per
the Series B Preferred Stock from and including the initial issuance
share of Series A Preferred Stock. The dividend rate forff
date of December 10, 2021 until the first reset date of December 15, 2026 will be 7.0% per annum of the $1,000 liquidation
preference per share of Series B Preferred Stock. On and after the first reset date of the Series A Preferred Stock, the dividend
rate on the Series A Preferred Stock for each subsequent five-year period (each, a Reset Period) will be adjusted based upon the
each Reset Period
applicable Treasury rate, plus a spread of 6.93% per annum; provided that the applicablea
will not be lower than 1.07%. On and after the first reset date of the Series B Preferred Stock, the dividend rate on the Series B
Treasury rate, plus a spread of 5.74% per
Preferred Stock for each Reset Period will be adjusted based upon the applicablea
annum; provided that the applicablea
In the event that the
Company does not exercise its option to redeem all the shares of Preferred Stock within 120 days after the first date on which a
Change of Control Trigger Event (as defined in the Certificate of Designation) occurs, the then-appli
the
Preferred Stock will be increased by 5.00%.

each Reset Period will not be lower than 1.26%.

Treasury rate forff

Treasury rate forff

dividend rate forff

cablea

a

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

Luminant's asset fleff et consists of power generation and battery ESS units in six ISOs/RTOs, with the location, ISO/RTO,

technology, primary fuel type, net capacity and ownership interest for each generation facility shown in the tablea

below:

Facility

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

Location

, TX

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

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

Technology
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
ST
ST
CT
ST
ST
CT
CT
ST
ST
Nuclear
rr
Solar/Batter
rr

y

Primary Fuel
(a)
Naturt al Gas
Naturt al Gas
Naturt al Gas
Naturt al Gas
Naturt al Gas
Naturt al Gas
Naturt al Gas
Coal
Coal
Natural Gas
Natural Gas
Natural Gas
Naturt al Gas
Naturt al Gas
Naturt al Gas
Naturt al Gas
Nuclear
enewablea

R

Total Texas Segment

Fayette
Hanging Rock

Masontown, PA
Ironton, OH

PJM
PJM

CCGT
CCGT

Naturat
Naturat

l Gas
l Gas

46

Net Capacity
(MW) (b)

366
1,912
1,047
1,076
1,596
1,054
787
2,250
1,600
260
630
921
390
325
685
244
2,300
180
17,623
726
1,430

Ownership
Interest (c)
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%

100%
100%

Facility

well

Kendall
Liberty
Ontelaunee
Sayreville
Washington
Calumet
Dicks Creek
Miami Fort (CT)
Pleasants
Richland
Stryker
Bellingham
Blackstone
Casco Bay
Lake Road
Masspower
Milford
Independence

Location
Hopewell, VA
Minooka, IL
Eddystone, PA
Reading, PA
Sayreville, NJ
Beverly, OH
Chicago, IL
Monroe, OH
North Bend, OH
Saint Marys,
rr WV
Defiance, OH
Stryker,
Bellingham, MA
Blackstone, MA
Veazie, ME
Dayville, CT
Indian Orchard, MA
Milford, CT
Oswego, NY

OH

rr

Total East Segmen

t

Moss Landing 1 & 2
Moss Landing
Oakland

Moss Landing, CA
Moss Landing, CA
Oakland, CA

Total West Segmen

t

Coleto Creek
Baldwin
Edwards
Newton
Joppa/EEI
Joppa CT 1-3
Joppa CT 4-5
Kincaid
Miami Fort 7 & 8
Zimmer

Goliad, TX
Baldwin, IL
Bartonville, IL
Newton, IL
Joppa, IL
Joppa, IL
Joppa, IL
Kincaid, IL
North Bend, OH
Moscow, OH

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

CAISO
CAISO
CAISO

ERCOT
MISO
MISO
MISO
MISO
MISO
MISO
PJM
PJM
PJM

Technology
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CT
CT
CT
CT
CT
CT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT

CCGT
Battery
CT

ST
ST
ST
ST
ST
CT
CT
ST
ST
ST

Primary Fuel
(a)
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Fuel Oil
Natural Gas
Natural Gas
Fuel Oil
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas

Natural Gas
Renewable
Fuel Oil

Coal
Coal
Coal
Coal
Coal
t
Natural
Natural
t
Coal
Coal
Coal

Gas
Gas

Total Sunset Segment
Total capac

y
it

a

Net Capacity
(MW) (b)

370
1,288
607
600
349
711
380
155
77
388
423
16
566
544
543
827
281
600
1,212
2,093
1,020
400
110
,530
650
1,185
585
615
802
165
56
1,108
1,020
1,300
7,486
8,732

1

1

3

Ownership
Interest (c)
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%
80%
100%
80%
100%
100%
100%

___________
(a) Renewable represents generation assets fueled by renewablea

have significant fuel costs.

sources including energy storage and solar, which do not

(b) Unit capabi

a

lities are based on winter capac

a

ity and are reflected at our net ownership interest. We have not included units

that have been retired or are out of operation.

(c) Ownership interest of 100% indicates feeff

simple ownership of the facility. Ownership of less than 100% indicates the

share of ownership in the facility held by the Company.

See Note 3 to the Financial Statements for discussion of our solar and battery energy storage projects currently under

development and Note 4 to the Financial Statements for discussion of our retirement of certain generation facilities.

47

Our wholesale commodity risk management group also procures renewablea

generation in
ERCOT to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for renewablea
resources fromff
such customers. As of December 31, 2021, Vistra had long-term agreements to procure renewabla e energy
approximately 915 MW of renewable generation. These renewable generation sources deliver electricity when
credits fromff
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-dispatchablea
intermediate/load-following resources to respond to changes in their
output.

and create the need forff

energy credits fromff

renewablea

yll
Fuel Suppl
SS

Nuclear — We own and 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
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
the same year, which occurred in 2020. While one unit is
refueling cycle results in the refueling of both units during
undergoing a refueling outage, the remaining unit is intended to operate at full capaa
city. 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 facff

tor of 96%, 97% and 96% in 2021, 2020 and 2019, respectively.

ing (nuclear fuel

ity. Refuel

a
capac

d

ff

ff

ff

We have contracts in place for all of our 2022 and 2023 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 futff ure.

ff

t

Natural Gas — Our natural

t

MW and 13 peaking generation facilities totaling 5,022 MW. We satisfy off
combination of spot market and near-term purchase contracts. Additionally, we have near-term natural
agreements in place to ensure reliable fueff

gas-fueled generation fleff et is comprised of 23 CCGT generating facilities totaling 19,512
ilities through a
gas transportation

ur fuel requirements at these facff

l supply.

t

e — Our coal/lignite-fueled generation fleet is comprised of 10 generation facilities totaling 11,115 MW of
Coal/Li
i
gnit
ll
generation capac
the spring or fall off-peak demand periods. We
d
ity. Maintenance outages at these units are scheduled during
a
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 and coal purchased and transported by
railcar at the Coleto Creek and Martin Lake generation facilities.

Item 3. LEGAL PROCEEDINGS

See Note 13 to the Financial Statements for discussion of litigation, including matters related to our generation facilities

and EPA reviews.

Item 4. MINE SAFETY DISCLOSURES

Vistra 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 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 Safetyff
and
Health Act of 1977, as amended (the Mine Act), as well as other fede
ral and state regulatory agencies such as the RCT and
Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra'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,
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.

ff

48

PART II

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

ISSUER PURCHASES OF EQUITY SECURITIES

Vistra'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's common stock has been listed on the NYSE under the symbol "VST".

As of February 22, 2022, there were 448,803,986 shares of common stock issued and outstanding and 620 stockholders of

record.

In November 2018, we announced that the Board had adopted a common stock dividend program which we initiated in
the first quarter of 2019. Our common stockholders are entitled to receive any such dividends or other distributions ratably. In
February 2022, our Board declared a quarterly dividend of $0.17 per share that will be paid in March 2022. Each dividend
under the program is 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, Delaware law and contractual limitations. For additional details, see Item 1A. Riskii Factors and Note 14 to the
Financial Statements.

Stock Performance Graph

The perforff mance graph below compares Vistra's cumulative total returnt

on common stock for the period from May 10,
2017 (the date we were listed on the NYSE) through December 31, 2021 with the cumulative total returns
of the S&P 500
in each period
Stock Index (S&P 500) and the S&P Utility Index (S&P Utilities). The graph below compares the returnt
assuming that $100 was invested at May 10, 2017 in Vistra's common stock, the S&P 500 and the S&P Utilities, and that all
dividends were reinvested.

t

Comparison of Cumulative Total Return

Vistra Corp.
S&P 500
S&P Utilities

$225

$200

$175

$150

$125

$100

$75

05/10/17

12/31/17

12/31/18

12/31/19

12/31/20

12/31/21

49

Share Repurc

ee

hase Program

The following tablea

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

Section 12 of the Exchange Act, as amended, during the quarter ended December 31, 2021.

October 1 - October 31, 2021

November 1 - November 30, 2021

December 1 - December 31, 2021

For the quarter ended December 31, 2021

Total Number
of Shares
Purchased

Average
Price Paid
per Share

— $

5,094,030

14,236,335

19,330,365

$

$

$

—

20.22

21.50

21.16

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)

— $

5,094,030

14,236,335

19,330,365

$

$

$

2,000

1,897

1,591

1,591

In October 2021, we announced that the Board had authorized a new share repurchase program (Share Repurchase
o $2.0 billion of our outstanding common stock may be repurchased. The Share Repurchase
Program) under which up tu
Program became effective on October 11, 2021. The Share Repurchase Program supersedes the $1.5 billion share repurchase
program previously announced in September 2020, which had $1.325 billion of remaining authorization as of September 30,
2021. As an initial step in our broader capital allocation plan, we intend to use all of the net proceeds from our October 2021
Series A Preferred Stock offering to repurchase shares of our outstanding common stock. We expect to complete repurchases
under the Share Repurchase Program by the end of 2022.

Under the Share Repurchase Program, any purchases of shares of the Company's stock may be repurchased from time to
time in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying
eral securities laws. The actual timing, number and value of
with the Exchange Act or by other means in accordance with fedff
shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a
number of facff
al allocation priorities, the market price of our stock, general market and economic
conditions, applicablea

legal requirements and complim ance with the terms of our debt agreements.

tors, including our capita

See Note 14 to the Financial Statements forff more information concerning the Share Repurchase Program.

Item 6. [RESERVED]

Not applicable.

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

OPERATIRR

ONS

ff

tt

Act of 1o

The discussion below, as well as other portions of this aii

nnual report on Form 10-K, contain forward-looking statements
withitt n the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private SecSS urities Litigation
995. In addition, management may make forward-looking statements orally or in other writing, including, but
Reforme
rs and in
not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholde
eaders can usually identify t
he SEC. RCC
s “may,”
hese forward-looking statements by the use of such words add
other filff ings with t
“anticipates,” “believes” or similar words. These statements
“plans,” “projects,” “expects,”tt
“will,” “should,”l
“likelkk y,”ll
those anticipate
involve a number of risks akk
uch forward-
nd uncertainties. Actual results could materially diffeff r fromff
looking statements. ForFF more discussion about risk factors that could cause or contribute
to such diffeff rences, see Part I, Item
iscussed herein. Forward-looking statements refleff ct the inforff mation only as of the date on
1A "Riskii Factors" and other risks dkk
on to update any forward-looking statements to reflect
ny obligati
which they ae
does update one or more forward-looking statements, no inferenc
future events, devdd elopments, or other information.
e
should be drawn that additional updates will be made regarding that statement or any other forwff
ard-looking statements. ThisTT
discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity,yy
capital structure and business devdd elopments for the periods covered by the consolidated financial statements included under
Part II, Item 8 of to hitt s aii
nnual report on Form 10-K for the year ended December 31, 2021. This discussion should be read in
conjunction with those consolidated financial statements and the related notes and is qualifii ed by reference to them.

re made. The Company does not undertake akk
ii
If Vistra

d by sb

kk

ff

ff

i

i

tt

50

The folff

lowing discussion and analysis of our financial condition and results of operations for the years ended December
31, 2021, 2020 and 2019 should be read in conjunction with our consolidated financial statements and the notes to those
statements. The discussion and analysis of our financial condition and results of operations for the year ended December 31,
2019 and for the year ended December 31, 2020 compared to the year ended December 31, 2019 are included in Item 7.
Management's Discussion and Analysis
of Financial Condition and Results in our 2020 Form 10-K and are incorporated herein
by reference.

ll

All dollar amounts in the tablea

s in the following discussion and analysis are stated in millions of U.S. dollars unless

otherwise indicated.

Business

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

t

Operatingtt

Segme

e

nts

Vistra has six reportablea

segments: (i) Retail, (ii) Texas, (iii) East (iv) West, (v) Sunset and (vi) Asset Closure. See Note

20 to the Financial Statements forff

further information concerning our reportable business segments.

Significi

ant Activitiii es and Events and Itemtt

s Influenc

II

ing Future Performance

Winter Storm Ur

riUU

In February 2021, the U.S. experienced an unprecedented Winter Storm Uri, bringing extreme cold temperatures

to the
central U.S., including Texas. On February 12, 2021, the Governor of Texas declared a state of disaster forff
all 254 counties in
the State in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an
imminent threat dued
heavy snow, and freezing rain statewide. On February 14, 2021,
President Biden issued a fedff

eral emergency declaration for all 254 Texas counties.

zing temperatures,

to prolonged freeff

t

t

As part of its annual winter season preparations, our power plant teams executed a significant winter preparedness
strategy, which included installing windbreaks and large radiant heaters to supplement existing freeze protection and insulation
and performing preventative maintenance on freeze protection equipment such as the insulation and automatic circuitry
designed to keep pipes at the power plants from freezing. In addition, in anticipation of Winter Storm Uri we took additional
sufficiient water availil biabilili yty to run
steps to prepare, including procuring ddi
for ext dendedd p ieri dods

fying hthat freeze protectiion icirc iuits were operatiionall.

lonal ddemiine lrali dized water supplypply

traililers to ensure

iverifying

addi iti

dand

ffi

u

This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators,
and a significant load shed event (i.e., involuntary outages to customers across the system for varying periods of time) that was
ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Despite these challenges, we
estimate that our fleet generated approximately 25 to 30% of the power on the grid during the height of the outages, as
compared to our approximately 18% market share.

The weather event resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended
December 31, 2021 (see Note 1 to the Financial Statements), after taking into account approximately $544 million in
securitization proceeds Vistra expects to receive from ERCOT as further described below. The primary drivers of the loss were
gas-fueled
the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural
handling
gas deliverability issues and our coal-fueled power plants driven by coal fuel
power plants driven by natural
challenges, high fuel costs, and high retail load costs.

ff

t

t

51

As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market
participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to
distribute to load-serving entities (LSEs) that were charged and paid to ERCOT exceptionally high price adders and ancillary
In October 2021, the PUCT issued a debt obligation order approving ERCOT's $2.1
service costs during Winter Storm Uri.
billion financing and the methodology for allocation of proceeds to the LSEs. In December 2021, ERCOT finalized the amount
of allocations to the LSEs, and we expect to receive $544 million in proceeds from ERCOT in the second quarter of 2022. We
concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received are
e the $2.1
determinablea
billion funding approved in the debt obligation order. Accordingly, we recognized the $544 million in expected proceeds as an
expense reduction in the fourth quarter of 2021 within fuel
, purchased power costs and delivery fees in our consolidated
statements of operation.

and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuat

ff

t

We continue to be subject to the outcome of potential litigation arising from this event (including any litigation that we
may pursue or be a party to); or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle
pricing across any portion of the supply chain that is currently being considered or may be considered by any such parties. The
also continues to consider potential legislation, such as Senate Bill (SB) 1580, which was passed in May 2021.
Texas legislaturet
SB 1580 may impact the total amount of balances owed by electric cooperatives to the market. The potential impact of this
legislation is uncertain as the final details will be specific to each electric cooperative.

There have been several announced efforts by the state and federal governments and regulatory agencies to investigate
and determine the causes of this event and its impact on consumers. We have received a civil investigative demand from the
Attorney General of Texas as well as requests for information from ERCOT, NERC and other regulatory bodies related to this
event and may receive additional inquiries. We are cooperating with these entities and have responded to these requests. Those
efforts may result in changes in regulations that impact our industry including but not limited to additional requirements for
chain including generation, transmission, and fuel supply; improvements
winterization of various facets of the electricity supply
in coordination among the various participants in the electricity and natural
chains during any future event; potential
revisions to the method or calculation of market compensation and incentives relating to the continued operation of assets that
only run periodically, including during extreme weather events or other times of scarcity; and restrictions or limitations on the
types of plans permitted to be offered to customers. We are continuing to monitor this situation as it develops. The full impact
of litigation or any impacts of any legislative or regulatory changes or actions (including enforcement actions that may be
brought against various market participants) that may occur as a result of the event could have a material impact on our
business, financial condition, results of operations, or cash flows, but cannot be estimated at this time. See Note 13 to the
Financial Statements for further discussion of these matters.

u
gas supply

u

t

In response to the storm, Vistra committed to donate $5 million to assist Texas communities and individuals meet their
most pressing needs, including support for food banks and food pantries, critical needs, bill payment assistance, and more.
Vistra also assured residential customers across its retail brands that they would not see any near-term impact on their rates due
to the winter weather event, though bills could increase due to high usage during the cold weather period in February 2021.

Furthermore, Vistra has taken or intends to take various actions to improve its risk profile forff

future weather-driven
lities and to further
a
volatility events, including investing in improvements to furthe
weatherize its ERCOT fleet for even colder temperatures
ions; carrying more backup generation into the peak
seasons after accounting for weatherization investments and ERCOT market improvements implemented going forward;
contracting for incremental gas storage to support its gas fleet; adding additional dual fuel capabil
ities at its gas steam units and
increasing fuel oil inventory at its existing dual fuel sites; participating in processes with the PUCT and ERCOT for registration
of gas infrastructure as critical resources with the transmission and distribution utilities and for enhanced winterization of both
gas and power assets in the state; and engaging in processes to evaluate potential market reforms.

r harden its coal fuel

and longer durat

handling capabi

d

a

ff

ff

t

Climate Change, Investments

tt

in Clean EneEE rgy and CO2 Reductions

e

ions — We are subjeu

Environmental Regulat

ct to extensive environmental regulation by governmental authorities,
including the EPA and the environmental regulatory bodies of states in which we operate. Environmental regulations could
have a material impact on our business, such as certain corrective action measures that may be required under the CCR rulrr e and
the ELG rule. See "Item 1. Business – Environmental Regulations and Related Considerations," and "Item 1A. Risk Factors –
Regulatory and Legislative Risks" and Note 13 to the Financial Statements. However, such rules and the regulatory
environment are continuing to evolve and change, and we cannot predict the ultimate effect
that such changes may have on our
business.

ff

52

Emissii

ions Reductions — Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO2 equivalent emissions
by 2030 as compared to a 2010 baseline with a long-term goal to achieve net-zero carbon emissions by 2050, assuming
necessary advancements in technology and supportive market constructs and public policy. In furtherance of Vistra's efforts to
meet its net-zero target, Vistra expects to deploy multiple levers to transition the company to operating with net-zero emissions.

Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which
ncial instruments to fund new or existing projects that support renewabla e energy and energy
discussion of the Series B Preferred

allows us to issue green finaff
efficiency with alignment to our ESG initiatives. See Preferr
Securities issued under our Green Finance Framework.

ed Stock OffO eri

ngs below forff

ff

ff

Solar Generation and Energy Storage Projectstt — In January 2022, we announced that, subject to approva

l by the CPUC,
we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our
Moss Landing Power Plant site. In September 2021, we announced the planned development, at a cost of approximately $550
million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-
retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act. In September 2020,
we announced the planned development, at a cost of approximately $850 million, of up to 668 MW of solar photovoltaic power
generation facilities and 260 MW of battery ESS in Texas. We will only invest in these growth projects if we are confident in
the expected returns. See Note 3 to the Financial Statements forff

a summary of our solar and battery energy storage projects.

a

CO2 Reductdd

ions — In September 2020 and December 2020, we announced our intention to retire (a) all of our remaining
coal generation facilities in Illinois and Ohio, (b) one coal generation facility in Texas and (c) one natural
lity in Illinois
no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply
(see Note 13 to the Financial Statements), and in furtherance of our efforts to significantly
with the CCR rulrr e and ELG ruler
reduce our carbon footprint.
In April 2021, we announced we would retire the Joppa generation facilities by September 1,
2022, and in July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022. See Note 4 to the
Financial Statements for a summary of these planned generation retirements.

ff
gas faci

t

Moss Landing Outages

In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery Err

SS. A review
found that only a small, single digit-percentage of batteries at the facility were impacted and that the root cause originated in
systems separate from the battery srr
the facility to
service. Moss Landing Phase II was not affected by this incident.

ystem. The facility will be offlff ine as we perform the work necessary to returnt

In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery Err

SS. An
investigation is underway to determine the root cause of the incident. The facility will be offline as we perform the work
the facility to service. Moss Landing Phase I was not affected by the incident, but the facility will remain
necessary to returnt
offline during the assessment stage of the Moss Landing Phase II incident.

We do not expect these incidents to have a material impact on our results of operations.

Mining Reclamation Award

In October 2021, the Office of Surface Mining Reclamation and Enforcement (OSM) announced Luminant as a recipient
of its 2021 Excellence in Surface Coal Mining Reclamation Award for the work done to reclaim and restore previously mined
land at its Monticello-Winfield Mine. The award recognizes companies that achieve the most exemplary coal mine reclamation
in the nation. Luminant has a long history of environmental stewardship, reclaiming land long before being required under
federal or state law.

II
COVID-19

Pandemic

With the global outbreak of the novel coronavirus (COVID-19) and the declaration of a pandemic by the World Health
Organization on March 11, 2020, the U.S. government has deemed electricity generation, transmission and distribution as
providing essential services during this global emergency. As a provider of critical infrastructure,
"critical infrastructure"
Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains
focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the
continuity of its business operations.

t

53

We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19
pandemic to guide our emergency response, business continuity, and the precautionary measures we are taking on behalf of
employees and the public. We will continue to monitor developments affecting both our workforce and our customers, and we
easures that we determine are necessary in order to mitigate the
have taken, and will continue to take, health and safety mt
impacts. To date, as a result of these business continuity measures, the Company has not experienced material disruptions in
our operations due to COVID-19.

See Note 7 to the Financial Statements forff

a summary of certain tax-related impacts of the CARES Act to the Company.

The COVID-19 pandemic has presented potential new risks to the Company's business. Although there have been
logistical and other challenges to date, there has been no material adverse impact on the Company's results of operations for the
years ended December 31, 2021 and 2020. The situation surrounding COVID-19 remains fluid and the potential for a material
impact on the Company's results of operations, financial condition and liquidity increases the longer the virus impacts the level
of economic activity in the U.S. and globally. As a result, COVID-19 may have a range of impacts on the Company's
operations, the full extent and scope of which are currently unknown. See Part I, Item 1A Riskii Factors — The outbreak of
ave a material and adverse
II
COVID-
effeff ct on our business, financial condition, and results of operations.

19, or the future outbreak of any other highly i

tious or contagious diseases, could hl

nfecff

ll

Dividend Program

In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of

2019. See Note 14 to the Financial Statements forff more information about our dividend program.

ff
Preferre

d StocSS

ff
k OffO erings

On October 15, 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Offering). The net
proceeds of the Offering were approximately $990 million, after deducting underwriting commissions and offering expenses.
We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share
Repurchase Program (discussed below).

On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering)
under our Green Finance Framework. The net proceeds of the Series B Offering were approximately $985 million, after
deducting underwriting commissions and offering expenses. We intend to use the proceeds from the Series B Offering to pay
for or reimburse existing and new eligible renewable and battery ESS developments.

See Note 14 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B

Preferred Stock.

e
Share Repurchase

Program

In October 2021, we announced that the Board had authorized a new share repurchase program (Share Repurchase
Program) under which up to $2.0 billion of our outstanding common stock may be repurchased. The Share Repurchase
Program became effective on October 11, 2021. The Share Repurchase Program supersedes the $1.5 million share repurchase
program previously announced in September 2020 (2020 Share Repurchase Program). In the three months ended December 31,
2021, 19,330,365 shares of our common stock were repurchased under the Share Repurchase Program for approximately $409
million at an average price of $21.16 per share of common stock. As of December 31, 2021, approximately $1.591 billion was
available forff
additional repurchases under the Share Repurchase Program. From January 1, 2022 through February 22, 2022,
16,059,290 shares of our common stock had been repurchased under the Share Repurchase Program for $355 million at an
average price per share of common stock of $22.07, and at February
repurchase
under the Share Repurchase Program. See Note 14 to the Financial Statements for more information concerning the Share
Repurchase Program and the 2020 Share Repurchase Program.

22, 2022, $1.236 billion was available forff

rr

54

Debt Activity

t

al structure,

We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize
maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities
our capita
and/or reduce ongoing interest expense. While the financial impacts resulting fromff Winter Storm Uri caused an increase in our
consolidated net leverage, the Company remains committed to a strong balance sheet, and the anticipated securitization
us to further execute this objective. See Note 1 to the Financial Statements for
proceeds from ERCOT are expected to enablea
ERCOT, Note 11 to the Financial Statements for details of our long-term
details of the securitization proceeds receivable fromff
debt activity, and Note 10 to the Financial Statements for details of our accounts receivable finaff

ncing.

Commodity-Linked Revolving Credit Facilitytt

On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra
Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent
and collateral agent. The Credit Agreement provides forff
a $1.0 billion senior secured commodity-linked revolving credit
facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity provided under the Commodity-Linked
Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries
are parties as power prices increase from time-to time and for other working capita
al and general corporate purposes. See Note
11 to the Financial Statements forff more information concerning the Commodity-Linked Facility.

Capacity Marketstt

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

each planning year:

RTO zone
ComEd zone
MAAC zone
EMAAC zone
ATSI zone
DEOK zone

2021-2022

2022-2023

(average price per MW-day)

$

$

140.00
195.55
140.00
165.73
171.33
140.00

50.00
68.96
95.79
97.86
50.00
71.69

Our capac

a
2022-2023, are as follows:

ity sales in PJM, net of purchases, aggregated by planning year and capac

a

ity type through planning year

CP auction capac
a
Bilateral capac

a

ity sold, net (MW)

ity sold, net (MW)

Total segment capacity sold, net (MW)

Average price per MW-day

2021-2022

2022-2023

East Segment
6,384
200
6,584
159.18

$

Sunset Segment
3,028
50
3,078
148.83

$

East Segment
5,500
200
5,700
68.54

$

Sunset Segment
1,519
—
1,519
70.52

$

NYISOYY — The most recent seasonal auction results forff NYISO's Rest-of-Sta

ff

te zones, in which the capac

a

t
ity f

orff

our

Independence plant clears, are as follows forff

each planning period:

Price per kW-month

Winter
2021 - 2022
1.00

$

Summer
2022

$

—

55

Due to the short-term, seasonal naturt e of the NYISO capac

a

bilateral trades. Our capacity sales, aggregated by season through winter 2023-2024, are as foll

ff

ity auctions, we monetize the majora
ows:

ity of our capac

a

ity through

a
a
a

Auction capac
Bilateral capac
Total capac

ity sold (MW)
ity sold (MW)
ity sold (MW)
Average price per kW-month

Winter
2021 - 2022
125
1,017
1,142
0.94

$

$

Summer
2022

—
565
565
2.18

East Segment

Winter
2022 - 2023
—
212
212
1.31

$

$

Summer
2023

—
104
104
1.76

Winter
2023 - 2024
—
38
38
1.78

$

ISO-NENN — The most recent Forward Capaa

city Auction results forff

ISO-NE Rest-of-Pool,

ff

in which most of our assets are

located, are as foll

ff

ows for each planning year:

Price per kW-month

2021-2022

2022-2023

2023-2024

2024-2025

$

4.63

$

3.80

$

2.00

$

2.61

Performance incentive rules increase capac

ayments 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 capaa

city transactions that extend through planning year 2025-2026.

ity pt

a

a
a
a

Auction capac
Bilateral capac
Total capac

ity sold (MW)
ity st
old (MW)
ity sold (MW)
Average price per kW-month

East Segment

2021-2022

2022-2023

2023-2024

2024-2025

2025-2026

3,037
213
3,250
4.35

$

2,996
95
3,091
3.92

$

3,091
20
3,111
2.12

$

2,967
78
3,045
3.18

$

$

—
78
78
3.47

MISO — The capac

a

ity auction results forff MISO Local Resource Zone 4, in which our assets are located, are as follows for

each planning year:

Price per MW-day

2021-2022

$

5.00

MISO capacity sales through planning year 2024-2025 are as folff

lows:

2021-2022

2022-2023

2023-2024

2024-2025

Sunset Segment

Bilateral capac

a

ity sold in MISO (MW)

Total MISO segment capaa

city sold (MW)

3,012

3,012

1,075

1,075

569

569

Average price per kW-month

$

2.31

$

1.94

$

2.58

$

265

265

4.26

2022 through 2023 for Moss Landing, are as

West Segment

2022

2023

1,287

1,275

CAISO — Our capac

a

ity sales in CAISO, aggregated by calendar year forff

follows:

Bilateral capac

a

ity sold (Avg MW)

56

Key Operational Risks and Challenges

Following is a discussion of certain key operational risks and challenges facff

ing management and the initiatives currently
underway to manage such challenges. These matters involve risks that could have a material effeff ct on our business, results of
operations, liquidity, financial condition, cash flows, reputation, prospects and the market price forff
our securities (including our
common stock). See also Item 1A. Riskii Factors in this annual report on Form 10-K for additional discussion on risks that could
have a material effeff ct on our results of operations, liquidity, financial condition, cash flows, reputation, prospects and the
market price forff

our securities (including our common stock).

Natural Gas Price and Market HeatHH Rate Exposure

The price of power is typically set by natural

ilities, with wholesale prices generally tracking
increases or decreases in the price of natural
gas, with exceptions such as those periods during which ERCOT power prices rise
significantly as a result of the scarcity of available generation resources relative to power demand. In recent years, natural gas
supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural
gas
gas prices, and such prices have historically
extraction; this supply/demand environment has resulted in historically low natural
been volatile.

gas-fueled generation facff

t

t

t

t

t

In contrast to our natural

gas-fueled generation facff

gas prices have no significant effect on the
tors being equal, these
cost of generating power at our nuclear-, lignite- and coal-fueled facff
nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as wholesale electricity prices change either as
gas prices or market heat rates, because of the effect on our operating margins. A persistent
a result of changes in natural
decline in the price of natural
gas, if not offset by an increase in market heat rates, 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 and wholesale hedges.

ilities. Consequently, all other facff

ilities, changes in natural

t
t

t

t

The wholesale market price of electricity divided by the market price of natural

gas represents the market heat rate.
ted by a number of factors, including generation availability, mix of assets and the efficiency of the
Market heat rate can be affecff
ilities) in generating electricity. Our market heat rate exposure is
gas-fueled generation facff
marginal supplier (generally natural
ity of generation resources, such as additions and retirements of generation facilities, and
impacted by changes in the availabila
mix of generation assets. For example, increasing renewable (wind and solar) generation capac
ity generally depresses market
heat rates, particularly during periods when total demand is relatively low. However, increasing penetration of renewable
ity may also contribute to greater volatility of wholesale market prices independent of changes in the price of
generation capac
natural
Decreases in market heat rates decrease the value of our generation assets because
t
lower market heat rates result in lower wholesale electricity prices, and vice versa.

gas, given their intermittent nature.

a

a

t

t

As a result of our exposure to the variability of natural

t

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;
foll
ff
magnitude
improving retail customer service to attract and retain high-value customers.

and costs of commodity price, liquidity risk and retail demand variability; and

tely reflects the value of our product offering to customers, the

owing a retail pricing strategy that appropria

a

t

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. When natural gas prices are depressed, we continue to seek opportunities to
manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

57

Estimated hedging levels forff

generation volumes in our Texas, East, West and Sunset segments as of December 31, 2021

were as follows:

Nuclear/Renewable/Coal

//

Generation:

Texas
Sunset

Gas Generation:

Texas
East
West

2022

2023

90 %
98 %

71 %
94 %
100 %

55 %
47 %

8 %
35 %
6 %

a

provides approxi

The following sensitivity tablea

mate estimates of the potential impact of movements in power prices and
gas-fired generation as calculated using an
spark spreads (the difference between the power revenue and fuel expense of natural
assumed heat rate of 7.2 MMBtu/MWh) on realized pre-tax earnings (in millions) taking into account the hedge positions noted
above for the periods presented. The residual gas position is calculated based on two steps: first,
calculating the difference
gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to
between actual heat rates of our natural
gas exposure that is not already included in the gas generation spark
spark spreads; and second, calculating the residual natural
spread sensitivity shown in the tablea
below. The estimates related to price sensitivity are based on our expected generation,
related hedges and forward prices at December 31, 2021.

ff

ff

t

t

t

2022

2023

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

13

$

(11) $

13

$

(12) $

(6) $

6

4

$

$

(2) $

1

$

(1) $

— $

— $

1

$

(1) $

2

$

(1) $

53

(50)

39

(37)

(18)

10

32

(30)

(2)

2

4

(4)

—

—

32

(28)

:
Texas
ee

Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price

e
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power pric

Gas Generation: $1.00/MWh increase in spark spread

Gas Generation: $1.00/MWh decrease in spark spread

Residual Naturat

l Gas Position: $0.25/MMBtu increase in natural

t

gas price

Residual Natural

t

Gas Position: $0.25/MMBtu decrease in natural

t

gas price

East:

Gas Generation: $1.00/MWh increase in spark spread

Gas Generation: $1.00/MWh decrease in spark spread

Residual Natural

t

Gas Position: $0.25/MMBtu increase in natural

t

e
gas pric

Residual Natural

t

Gas Position: $0.25/MMBtu decrease in natural

t

gas price

West:

Gas Generation: $1.00/MWh increase in spark spread

Gas Generation: $1.00/MWh decrease in spark spread

Residual Natural

t

Gas Position: $0.25/MMBtu increase in natural

t

gas price

Residual Natural Gas Position: $0.25/MMBtu decrease in natural

t

gas price

Sunset:

Coal Generation: $2.50/MWh increase in power price

Coal Generation: $2.50/MWh decrease in power price

58

Competitive Retail Mii

arMM kerr

ts and CusCC tomer 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 approximately 3%, 1% and 2% in
2021, 2020 and 2019, respectively. Based upon December 31, 2021 results discussed below in Results of Operations, a 1%
decline in retail customers in ERCOT would result in a decline in annual revenues of approximately $56 million. In responding
to the competitive landscape in the ERCOT market, we have attempted to reduce overall customer losses by focusing
on the
following key initiatives:

ff

•

•

• 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
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
t
contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and
; tactical programs we have initiated include
marketing efforts and to more effectively deploy our direct-sales force
improved customer service, aided by an enhanced customer management system, new product price/service offerings
and a multichannel approach for the small business market.

ff

Exposures Related to Nuclear Asset Outages

tt

a

ity of 1,150 MW. As of December 31, 2021, these units represented approxi

Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate
generation capac
mately 6% of our total generation
capac
a
ity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear
impact to pretax earnings is estimated (based upon
generation units experienced an outage at the same time, the unfavorablea
forward electricity market prices for 2022 at December 31, 2021) to be approximately $2 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 13 to the Financial Statements to understand the importance and limits of our insurance protection.

a

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
things, operations, maintenance, emergency planning, security, and
regulation by the NRC, covering, among other
al or
environmental and safety protection. The NRC may implement changes in regulations that result in increased capita
operating costs and may require extended outages, modify, suspend or revoke operating licenses and impose fines forff
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
(NEI). We also apply the knowledge
NRC, the Institutet
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,ff
and efficient operations
at the facff

of Nuclear Power Operations (INPO) and the Nuclear Energy Institutet

reliablea

ility.

59

Cyber/Da//

ta Securityii and Infrastruc

tt

ture ProtePP

ctiontt

Riskii

A breach of cyber/data security measures that impairs our information technology infrastructure,

operations technology
systems, supporting components, and/or associated sites utilized by the Company or one of our service providers could disrupt
normal business operations and affect our ability to control our generation assets, access retail customer information and limit
communication with third parties. Breaches and threats are becoming increasingly sophisticated, complex, change frequently
and may be difficult to detect, and our increased use of remote work environments and virtual
platforms in response to the
COVID-19 pandemic may also increase our risk of cyber-attack or data security breaches. Any loss of confidential or
proprietary data through a breach could materially affect our reputation, including our TXU Energy, Ambit Energy, Value
Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric brands,
expose the company to legal claims, significant liabilities, reputational damage, regulatory action, and disrupt business
operations, which could impair our ability to execute on business strategies.

t

t

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 Federal Bureau of Investigation, Cybersecurity and Infrastructure Security
Agency, U.S. Department of Homeland Security, Electricity Information Sharing and Analysis Center, U.S. Cyber Emergency
Response Team, the NRC and NERC.

While the Company has not experienced a cyber/data event causing any material operational, reputational or finaff

ncial
ce and our industry, and are proactively making strategic
impact, we recognize the growing threat within the general marketplat
investments in our perimeter and internal defenses, cyber/data security operations center and regulatory compliance activities.
We have controls in place designed to protect our infrastructure,
provide our employees awareness training of cybersecurity
threats, routinely utilize information technology security experts to assist us in our evaluations of the effectiveness of our
information technology systems and controls, and we regularly enhance our security measures to protect our systems and data,
including encryption, tokenization and authentication technologies to mitigate cybersecurity risks and increasing our monitoring
capabi
lities to enhance early detection and rapid response to potential cyber threats. In response to the fact that a portion of our
a
workforce continues to work remotely and within a hybrid work environment, we have reduced our attack surface process and
technology, which removes remote network risk fromff

our internal systems, assets, or data.

t

We also apply the knowledge gained through industry and government organizations, external partner cyber risk and
maturity assessments to continuously improve our technology, processes and services to detect, mitigate and protect our cyber
and data assets.

Seasonalitll ytt

ed by weather. As a result, our operating results
The demand for and market prices of electricity and natural
tuate on a seasonal basis. Typically, demand for and the
are impacted by extreme or sustained weather conditions and may flucff
price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for
gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme
and price of natural
winter weather have made, and may make such fluctuations more pronounced. The pattern of this flucff
tuation may change
depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.

gas are affect

ff

t

t

Application of Critical Accounting Policies and Estimates

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 assumptim ons 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 assumptim ons or estimation methodologies.

Derivativtt e Inst

II

rumtt

ents and Mark-to-Marke

tt

t Accountingn

We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative
instruments such as options, swaps,a
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 assumptim ons and estimation
techniques.

60

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 forff
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
gas, electricity, etc.), time period specified and delivery point. Where quoted
dependent on the type of commodity (e.g., natural
market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative
instrume
gas
r
and coal, (ii) electricity, natural
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 proprietary modeling techniques that
take into account availablea market information and other inputs that might not be readily observable in the market. We estimate
fair value as described in Note 15 to the Financial Statements.

nts valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity, natural
gas and coal options, and (iii) financial transmission rights.

t

t

t

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 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 are legally characterized as settlement of derivative contracts rather than collateral.

See Note 16 to the Financial Statements forff

further discussion regarding derivative instruments.

Accountingii

for Income Taxes

Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra is the
corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the 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
ities, as well as current and noncurrent accruals, involve estimates
judgments. Amounts of deferred income tax assets and liabila
In assessing the
and judgments of the timing and probability of recognition of income and deductions by taxing authorities.
taxablea
likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future
to the future impacts of various items, including changes
income. Actual income taxes could vary f
estimated amounts dued
l review of filed
in income tax laws, our forecasted financial condition and results of operations in future periods, as well as finaff
tax returns by taxing 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.

ct to examination by applicable tax authorities.

Income tax returns

are regularly subjeu

romff

rr

ff

ff

t

See Notes 1 and 7 to the Financial Statements forff

further discussion of income tax matters.

61

Accounting forff Tax Receivable Agreement

ff

ights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA RRR

On the Effective Date, Vistra entered into a tax receivable agreement (the TRA)RR with a transfer agent. Pursuant to the
ights under
TRA,RR we issued the TRA RRR
value in the amount of $574
the Plan of Reorganization. Vistra reflected
million as of the Effective Date related to these future payment obligations. As of December 31, 2021, the TRA oRR
bligation has
been adjusted to $395 million. During the year ended December 31, 2021, we recorded a decrease to the carrying value of the
bligation totaling $115 million as a result of adjustments to forecasted taxable income, including the financial impacts of
TRA oRR
planned additional renewabla e development
Winter Storm Uri, and anticipated tax benefits available under current tax laws forff
projects. As of December 31, 2021, expected undiscounted federal and state payments under the TRA iRR
s estimated to be
approximately $1.4 billion. The TRA oRR
bligation value is the discounted amount of projected payments to be made each year
under the TRA, based on certain assumptions, including but not limited to:

the obligation associated with TRA RRR

ights at fair

ff

•

•

•
•
•

•

•

taxable income by year forff

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
ff
future
to utilize the deductions arising out of
the Company generally expects to generate sufficient taxable income to be ablea
(i) the tax basis step up au
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 Effective 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 now operates in, the relevant tax rates of those states and how income will be apport
to those states.

years of 22.9%;

ttributablea

years;

futuret

ioned

a

ff

We recognize accretion expense over the life of the TRA RRR

ights liability as the present value of the liability is accreted upu
over the life of the liability. This noncash accretion expense is reported in the consolidated statements of operations 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 federal and state tax laws and regulations, changes in estimates of the
amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary
book/tax differences and other items. Changes in those estimates are recognized as adjustments to the related TRA RRR
ights
liability, with offsetting impacts recorded in the consolidated statements of operations as Impacts of Tax Receivable
Agreement. See Note 8 to the Financial Statements.

Asset Retirement Obligati

i

ons (ARO)

As part of business combination accounting, new fair values were establa ished for all AROs assumed in the Merger. A
liability is initially recorded at fair value forff
an ARO associated with the legal obligation associated with law, regulatory,
contractual or constructive retirement requirements of tangible long-lived assets. Changes to the estimate of the ARO requires
us to make significant estimates and assumptim ons. Specifically, the estimates and assumptim ons required for the mining land
reclamation related to lignite mining, such as the costs to fill in mining pits and interpreting the mining permit closure
requirements, are complex and require a significant amount of judgment. To develop the estimate associated with the costs to
fill in mining pits, we utilize a complex proprietary model to estimate the volume of the pit. A significant portion of the
estimate is associated with the Asset Closure Segment, thus related to closed facilities with changes in the estimate recorded to
our consolidated statements of operations.

For the next five years, Vistra is projected to spend approximately $265 million (on a nominal basis) to achieve its
reclamation objectives. During the years ended December 31, 2020 and 2019, we transferred $15 million and $135 million,
remediation. Any remaining unpaid third-party obligation was reclassified
respectively, in ARO obligations to third parties forff
d credits in our consolidated balance sheets.
to other current liabilities and other noncurrent liabilities and deferre

ff

62

As of December 31, 2021, the carrying

value of our ARO related to our nuclear generation plant decommissioning totaled
$1.635 billion and includes an assumption that Vistra receives a license extension of 20 years from the NRC to continue to
operate the Comanche Peak facff
through the regulatory
rate making process as part of Oncor's delivery fees and therefore changes in estimates of the ARO do not impact Vistra's
earnings.

ility. The costs to ultimately decommission that facff

ility are recoverablea

rr

See Note 21 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO

obligation estimates during

d

the years ended December 31, 2021, 2020 and 2019.

ii
Impairme

nt of GooGG dwillii and Other Long-Lived Assets

ff

impairment,

te lives) forff

We evaluate long-lived assets (including intangible assets with fini

in accordance with
accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances
. For our generation assets, possible indications include an
indicate that their carrying amount may not be recoverablea
expectation of continuing long-term declines in naturat
l 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 naturet
and
may require the use of estimates in forec
asting future results and cash flows related to an asset or group of assets. Further, the
of our property, plant and equipment, which includes a fleff et of generation assets with a diverse fuel mix and
unique naturet
judgments in
individual generation units that have varying production or output rates, requires the use of significant
determining the existence of impairment indications and the grouping of assets for impairment testing. See Note 21 to the
Financial Statements forff
discussion of impairments of long-lived assets recorded in the years ended December 31, 2021 and
2020.

ff

Recoverabila

ity of long-lived assets is determined by a comparison of the carrying amount of the long-lived asset group to
the net cash flows expected to be generated by the asset group, through considering specific assumptim ons for forward natural
gas and electricity prices, forward capac
s, generation plant performance,
forecasted fuel prices and forecasted operating costs. The carrying value of such asset groups is
forecasted capital expenditures,
if the projected undiscounted cash flows are less than the carrying value.
determined to be unrecoverablea

ity prices, the effects of enacted environmental ruler

a

t

t

, faiff

If an asset group carrying value is determined to be unrecoverablea

r value will be calculated based on a market
participant view and a loss will be recorded for the amount the carrying value exceeds the fair value. Fair value is determined
primarily by discounted cash flows (income approach) and supported by available market valuations, if applicable. The income
approach involves estimates of future performance
gas
t
s, generation plant
and electricity prices, forward capac
a
performance, forecasted capital expenditures and forecasted fuel
ch is the
Any significant change to one or more of these factors can have a material
discount rate appli
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.

that reflect assumptions regarding, among other things, forward natural

ity prices, market heat rates, the effects of enacted environmental ruler

prices. Another key assumptim on in the income approa

ed to the forecasted cash flows.

a

a

ff

ff

ff

Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the trade names of TXU
EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield, Dynegy Energy Services, TriEagle Energy, Public Power and U.S.
Gas & Electric, respectively, are required to be evaluated forff
impairment at least annually (we have selected October 1 as our
annual goodwill 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 comparablea
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 Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2021.
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.

63

Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2021, $2.461 billion of
our goodwill was allocated to our Retail reporting unit and $122 million was allocated to our Texas Generation reporting unit.
Goodwill impairment testing is performff
ed 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 excess carryirr ng value is
written off as an impairment charge.

t

ff

e that reflect assumptions regarding, among other things, forward natural

The determination of enterprise value of a reporting unit 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
publicly traded company values (market approach). The income approach
flow analyses (income approach), and comparablea
involves estimates of future performanc
gas and
electricity prices, market heat rates, the effect
s, generation plant performance, forecasted capital
and retail sales volume trends, as well as determination of a terminal value. Another key variable in the income
expenditures
The determination of
approach is the discount rate, or weighted average cost of capita
the discount rate takes into consideration the capita
publicly
traded companies as well as an estimate of returnt
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 appl
y to the EBITDA of our reporting units. Critical judgments include the selection of
publicly traded comparablea
companies and the weighting of the value metrics in developing the best estimate of enterprise
value.

al structure, credit ratings and current debt yields of comparablea

on equity that reflects historical market returns

ied to the forecasted cash flows.

s of environmental rulerr

a
al, appl

a

ff

ff

t

t

RESULTS OF OPERATRR IONS

Vistra Consolidat

CC

ii
edtt Financ

ial Results — YeaYY r Ended

EE

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

Operating income (loss)

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

Agreement

Income (loss) before income taxes

Income tax (expense) benefit

Net income (loss)

December 31, 2021 Compared to Year Ended December 31, 2020

Year Ended December 31,

2021

2020

Favorable
(Unfavorable)
$ Change

$

$

$

12,077
(9,169)
(1,559)
(1,753)
(1,040)
(71)
(1,515)
140
(16)
(384)
53
—
(1,722)
458
(1,264) $

11,443
(5,174)
(1,622)
(1,737)
(1,035)
(356)
1,519
34
(42)
(630)
5
4
890
(266)
624

$

$

634
(3,995)
63
(16)
(5)
285
(3,034)
106
26
246
4
8
(4)
(2,612)
724
(1,888)

64

Retail

Texas

$

7,871

$

2,790

$

East
2,587

Year Ended December 31, 2021

West

Sunset

Asset
Closure

Eliminations
/ Corporate
and Other

$

374

$

739

$

— $

(2,284) $

Vistra
Consolidated
12,077

(4,568)
(127)

(3,991)
(704)

(2,123)
(243)

(253)
(37)

(212)

(608)

(698)

(718)

(88)

(75)

(33)
2,213
1
(7)

(9)

—

—
(2,601)
84
(9)

14

—

—
(552)
—
—

(15)

—

2,198

(2,512)

(567)

(2)
2,196

$

—

$ (2,512) $

—
(567) $

(60)

(32)

—
(8)
—
—

9

—

1

—
1

(518)
(417)

(139)

(55)

(38)
(428)
15
2

(2)

—

—
(30)

—

(26)

—
(56)
35
—

(1)

—

2,284
(1)

(36)

(46)

—
(83)
5
(2)

(9,169)
(1,559)

(1,753)

(1,040)

(71)
(1,515)
140
(16)

(380)

(384)

53

53

(413)

(22)

(407)

(1,722)

—
(413) $

$

—
(22) $

460
53

$

458
(1,264)

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

Operating income (loss)

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

income taxes
Income tax benefit
(expense)

Net income (loss)

Operating revenues

$

8,270

$

4,116

$

Retail

Texas

East
2,415

West

Sunset

$

282

$

1,252

$

Asset
Closure
3

Year Ended December 31, 2020

Eliminations
/ Corporate
and Other

$

(4,895) $

Vistra
Consolidated
11,443

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

Operating income (loss)

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

income taxes
Income tax expense

Net income (loss)

$

(6,857)
(123)

(1,078)
(727)

(1,262)
(270)

(303)

(475)

(721)

(675)

(75)

—
312
6
1

(10)

—

—

309

—
309

—
1,761
3
(12)

8

—

—

1,760

—
1,760

$

$

(89)

—
73
1
(30)

(7)

—

4

41

—
41

65

$

(168)
(30)

(19)

(26)

—
39
1
—

10

—

—

50

—
50

(704)
(408)

(133)

(71)

(356)
(420)
6
2

(2)

—

—

—
(63)

(22)

(27)

—
(109)
10
(2)

—

—

—

4,895
(1)

(64)

(72)

—
(137)
7
(1)

(629)

5

—

(414)

(101)

(755)

—
(414) $

—
(101) $

(266)
(1,021) $

$

(5,174)
(1,622)

(1,737)

(1,035)

(356)
1,519
34
(42)

(630)

5

4

890

(266)
624

rr
In February

2021, Winter Storm Uri resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the
year ended December 31, 2021, after taking into account approximately $544 million in securitization proceeds Vistra expects
r described in Note 1 to the Financial Statements. For the remainder of 2021, our operating
to receive from ERCOT as furthe
on cost management and self-help activities while
ff
segments delivered strong operating performance with a disciplined focus
generating and selling essential electricity in a safe and reliable manner.

ff

Consolidated results decreased $3.034 billion to a net operating loss of $1.515 billion in the year ended December 31,
2021 compared to the year ended December 31, 2020. The change in results was driven by the Winter Storm Uri impacts,
including the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural
gas deliverability issues and our coal-fueled power plants driven by coal fuel
gas-fueled power plants driven by natural
handling challenges, high fuel costs, and high retail load costs including ancillary service costs and reliabila
ity deployment price
adders. Results were adversely impacted by $759 million in pre-tax unrealized losses on commodity hedging transactions in
2021 compared to $231 million in pre-tax unrealized gains on commodity hedging transactions in 2020. Power, natural
gas and
coal forward
market curves moved up during the year ended December 31, 2021, driving these net pre-tax unrealized losses on
ff
commodity hedging transactions.

ff

t

t

t

Operating costs decreased $63 million to $1.559 billion in the year ended December 31, 2021 compared to the year ended

December 31, 2020 primarily driven by lower LTSA costs and lower property taxes.

Interest expense and related charges decreased $246 million to $384 million in the year ended December 31, 2021
compared to the year ended December 31, 2020 driven by $134 million in unrealized mark-to-market gains on interest rate
swaps in 2021 compared to $155 million in unrealized mark-to-market losses on interest rate swapsa
in 2020. See Note 21 to the
Financial Statements.

For the years ended December 31, 2021 and 2020, the impacts of the TRA tRR otaled income of $53 million and $5 million,

respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation.

For the year ended December 31, 2021, income tax benefit totaled $458 million and the effective tax rate was 26.6%. For
totaled $266 million and the effective tax rate was 29.9%. See Note 7 to

the year ended December 31, 2020, income tax benefitff
the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

ff

Consolidated cash flows

used in operations totaled $206 million for the year ended December 31, 2021 compared to
consolidated cash flows provided by operations of $3.337 billion for the year ended December 31, 2020. The unfavorablea
change of $3.543 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash
margin deposits posted with third-parties. Cash margin deposits posted were driven by net pre-tax unrealized losses on
commodity hedging transactions reflecting power, natural
market curves that moved up during the year
ended December 31, 2021.

gas and coal forward

ff

t

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 performff
ance 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 tablea
s 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 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 filff ed reports in
their entirety and not rely on any single finff ancial measure.

66

BB

EBITDATT

and Adjustedtt EBITDA

— We believe EBITDA and Adjusted EBITDA provide meaningful representations of
ncial perforff mance on an ongoing basis.
our operating performance. We consider EBITDA as another way to measure finaff
Adjusted EBITDA is meant to reflect the operating performance of our segments forff
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, (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.

ff

Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine
ance against our peers, and evaluate overall financial performance, we

al expenditures, assess performff

our ability to fund capita
believe they provide useful information for investors.

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

comparablea

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

Adjustedtt EBITBB DATT — YeaYY r Ended

EE

December 31, 2021 Compared to Ytt

earYY

Ended December 31, 2020

Net income (loss)

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

EBITDA

/

Agreement

se accounting impacts

Unrealized net (gain) loss resulting from commodity hedging transactions
Generation plant retirement expenses
Fresh start/purcha
Impacts of Tax Receivablea
Non-cash compensation expenses
Transition and merger expenses
Other, including impairment of long-lived and other assets
Loss on disposal of investment in NELP
COVID-19-related expenses (c)
Winter Storm Uri impacts (d)

Adjusted EBITDA

Year Ended December 31,

2021

2020

Favorable
(Unfavorable)
$ Change

$

$

(1,264) $
(458)
384
1,831
493
759
18
(138)
(53)
51
(8)
80
—
8
698
1,908

$

624
266
630
1,812
3,332
(231)
43
38
(5)
63
16
375
29
25
—
3,685

$

$

(1,888)
(724)
(246)
19
(2,839)
990
(25)
(176)
(48)
(12)
(24)
(295)
(29)
(17)
698
(1,777)

____________
(a)

Includes unrealized mark-to-market net gains on interest rate swapsa
losses on interest rate swapsa

of $155 million for the years ended December 31, 2021 and 2020, respectively.

of $134 million and unrealized mark-to-market net

(b) Includes nuclear fuel

ff

amortization in the Texas segment of $78 million and $75 million for the years ended December 31,

2021 and 2020, respectively.
Includes material and supplies and other incremental costs related to our COVID-19 response.

(c)
(d) For the year ending December 31, 2021, includes the following of the Winter Storm Uri impacts, which we believe are not
reflective of our operating performance: allocation of ERCOT default uplift charges which are expected to be paid over
more than 90 years under current protocols; accrual of Koch earn-out amounts that the Company will pay by the end of
her described below); and Winter Storm
the second quarter of 2022; future bill credits related to Winter Storm Uri (as furt
Uri related legal fees
and other costs. The adjustment for future bill credits relates to large commercial and industrial
customers that curtailed their usage during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future
periods as the credits are applied to customer bills. We estimate the amounts to be applied in future
periods are 2022
(approximately $150 million), 2023 (approximately $67 million), 2024 (approximately $11 million) and 2025
(approximately $4 million). The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in
the years in which such bill credits are applied more accurately reflects its operating performance.

ff

ff

ff

67

Year Ended December 31, 2021

Texas

East

$ (2,512) $ (567) $

Asset
Closure

Sunset
$ (413) $ (22) $

Net income (loss)

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

EBITDA

/

se accounting impacts

Unrealized net (gain) loss resulting
from commodity hedging transactions
Generation plant retirement expenses
Fresh start/purcha
Impacts of Tax Receivablea
Non-cash compensation expenses
Transition and merger expenses
Other, including impairment of long-
lived and other assets
COVID-19-related expenses (c)
Winter Storm Uri impacts (d)

Agreement

Retail
$2,196
2
9
212
2,419

(1,403)
—
2
—
—
(2)

57
—
239

—
(14)
686
(1,840)

1,139
—
(14)
—
—
—

18
4
457

—
15
698
146

655
—
(74)
—
—
—

9
1
—

West
1
—
(9)
60
52

38
—
—
—
—
—

3
—
—

93

—
2
139
(272)

330
18
(52)
—
—
—

33
2
1

60

$

Eliminations
/ Corporate
and Other
53
(460)
380
36
9

Vistra
Consolidated
(1,264)
$
(458)
384
1,831
493

759
18
(138)
(53)
51
(8)

80
8
698

—
—
—
(53)
51
9

(43)
1
1

—
1
—
(21)

—
—
—
—
—
(15)

3
—
—

Adjusted EBITDA

$1,312

$ (236) $ 737

$

$ (33) $

(25) $

1,908

ff

Includes $134 million of unrealized mark-to-market net gains on interest rate swaps.a

amortization of $78 million in the Texas segment.
Includes material and supplies and other incremental costs related to our COVID-19 response.

____________
(a)
(b) Includes nuclear fuel
(c)
(d) Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance:
allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current
protocols; accrual of Koch earn-out amounts that the Company will pay by the end of the second quarter of 2022; future
and other
bill credits related to Winter Storm Uri (as furt
costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage
during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to
customer bills. We estimate the amounts to be applied in future
periods are 2022 (approximately $150 million), 2023
ff
(approximately $67 million), 2024 (approximately $11 million) and 2025 (approximately $4 million). The Company
believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are
applied more accurately reflects its operating performance.

her described below); and Winter Storm Uri related legal fees

ff

ff

68

Year Ended December 31, 2020

Asset
Closure

Sunset
$ (414) $ (101) $

Eliminations
/ Corporate
and Other

Vistra
Consolidated
624
266
630
1,812
3,332

(1,021) $
266
629
64
(62)

—
—
—
(5)
63
11

(231)
43
38
(5)
63
16

375
29
25
3,685

359
—
5
$ 242

1
—
—
$ (81) $

(36)
—
2
(27) $

Net income (loss)

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

EBITDA

Retail
$ 309
—
10
303
622

Texas
$1,760
—
(8)
550
2,302

$

East

41
—
7
721
769

$

West
50
—
(10)
19
59

/

se accounting impacts

Unrealized net (gain) loss resulting from
commodity hedging transactions
Generation plant retirement expenses
Fresh start/purcha
Impacts of Tax Receivablea
Non-cash compensation expenses
Transition and merger expenses
Other, including impairment of long-
lived and other assets
Loss on disposal of investment in NELP
COVID-19-related expenses (c)

Agreement

Adjusted EBITDA

340
—
5
—
—
5

(691)
—
(8)
—
—
2

15
—
22
—
—
1

11
—
—
$ 983

26
—
15
$1,646

10
29
3
$ 849

$

10
—
—
—
—
—

4
—
—
73

—
2
133
(279)

95
43
19
—
—
—

—
—
22
(79)

—
—
—
—
—
(3)

____________
(a)
(b) Includes nuclear fuel
(c)

ff

Includes $155 million of unrealized mark-to-market net losses on interest rate swaps.a

amortization of $75 million in the Texas segment.
Includes material and supplies and other incremental costs related to our COVID-19 response.

69

Retail Segme

e

nt — Year Ended December 31, 2021 Comparem

d to Ytt

earYY

Operating revenues:

Revenues in ERCOT
tt
Revenues in Northeast/Mi
Amortization expense
Unrealized net losses on hedging activities (a)

dwest

Total operating revenues

Fuel, purchased power costs and delivery fees:

iates

Purchases from affilff
Unrealized net gains (losses) on hedging activities with affiliates
Unrealized net gains on hedging activities
Delivery fees
Other costs (b)

Total fuel, purchased power costs and delivery fees

Net income

Adjusted EBITDA

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

tt

dwest

Total retail electricity sales volumes

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

Ended December 31, 2020

Year Ended December 31,

2021

2020

Favorable
(Unfavorable)
Change

$

$

$

$

$

5,943
2,255
(2)
(325)
7,871

(4,002)
1,719
9
(1,937)
(357)
(4,568)

2,196

1,312

$

$

$

$

$

5,880
2,406
(5)
(11)
8,270

(4,566)
(329)
—
(1,893)
(69)
(6,857)

309

983

$

$

$

$

$

57,033
36,070
93,103

54,075
36,274
90,349

90.0 %
92.0 %

90.0 %
91.0 %

63
(151)
3
(314)
(399)

564
2,048
9
(44)
(288)
2,289

1,887

329

2,958
(204)
2,754

____________
(a) For the year ended December 31, 2021, a net loss of $298 million was recognized in operating revenues due to the third
quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical
settlement is no longer considered probable throughout the contract term.

(b) For the year ended December 31, 2021, includes $153 million of future bill credits to large commercial and industrial

customers.

(c) Weather data is obtained fromff

Weatherbank, Inc. For the year ended December 31, 2021, normal is defined as the
average over the 10-year period from December 2011 to December 2020. For the year ended December 31, 2020, normal
is defined as the average over the 10-year period from December 2010 to December 2019.

70

The folff

lowing table presents changes in net income (loss) and Adjusted EBITDA forff

the year ended December 31, 2021

compared to the year ended December 31, 2020.

Winter Storm Uri, including securitization proceeds receivable fromff
Monetization of certain commercial positions
Higher margins
Other driven by higher SG&A expense

Change in Adjusted

d

EBITDA

ERCOT and bill credits

Favorable impact of higher unrealized net gains on commodity hedging activities
Future bill credits and other costs related to Winter Storm Uri
Decrease in depreciation and amortization expenses
Other, including impairment of long-lived and other assets

Change in Net income

Year Ended
December 31, 2021
Compared to 2020
(75)
$
207
228
(31)
329
1,743
(245)
91
(31)
1,887

$

$

Generation — Year Ended December 31, 2021 Compared to Ytt

earYY

Ended December 31, 2020

ity revenue from ISO/RTO

Operating revenues:
Electricity sales
Capac
a
Sales to affiliates
Rolloff of unrealized net gains
(losses) representing positions
settled in the current period
Unrealized net gains (losses) on
hedging activities
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) losses fromff
hedging activities
Ancillary and other costs

Fuel, purchased power costs
and delivery fees

Texas

East

West

Sunset

2021

2020

2021

2020

2021

2020

2021

2020

Year Ended December 31,

$ 1,999
—
2,063

$ 896
—
2,543

$1,619
(22)
1,553

$ 833
(52)
1,655

$ 410
1
5

$ 289
—
3

$ 819
184
382

$ 883
164
365

(207)

2

(159)

159

62

(22)

241

(205)

(37)

217

51

(121)

(104)

(1,028)
—
2,790

458
—
4,116

(529)
74
2,587

(61)
2
2,415

—
—
374

12

—
—
282

(713)

133

(162)
(12)
739

(68)
(20)
1,252

(2,829)

(960)

(2,072)

(1,225)

(251)

(166)

(810)

(744)

—

6

133
(1,295)

14
(138)

2

(18)
(35)

(8)

8
(37)

—

4
(6)

—

—
(2)

(4)

304
(8)

2

45
(7)

(3,991)

(1,078)

(2,123)

(1,262)

(253)

(168)

(518)

(704)

Net income (loss)

$(2,512)

$1,760

$ (567)

$

41

$

1

$ 50

$ (413)

$ (414)

Adjusted EBITDA

$ (236)

$1,646

$ 737

$ 849

$ 93

$ 73

$

60

$ 242

Production volumes (GWh):

Natural gas facilities
Lignite and coal facff
Nuclear facilities
Solar/Battery facilities

ilities

Capacity factors:
CCGT facilities
Lignite and coal facff
Nuclear facilities

ilities

Weather - percent of normal (a):

30,921
25,513
19,402
454

35,093
26,013
19,480
432

43.2 % 49.2 %
75.6 % 77.1 %
96.3 % 96.7 %

55,428

55,938

5,365

5,284

36,953

29,971

4

57.6 % 57.9 % 60.0 % 59.1 %

58.0 % 47.1 %

Cooling degree days
Heating degree days

94 %
94 %

98 %
85 %

108 %
93 %

105 %
92 %

90 %
111 %

130 %
95 %

115 %
90 %

102 %
89 %

____________
(a) Reflects cooling degree days or heating degree days for the region based on Weather Services Internat

r

ional (WSI) data.

72

Year Ended December 31,

2021

2020

Market pricing

Average ERCOT North power
price ($/MWh)

$ 149.57

Average NYMEX Henry Hubu
t
natural

gas price ($/MMBtu)
Average natural gas price (a):

TetcoM3 ($/MMBtu)
Algonquin Citygates ($/MMBtu)

$

$
$

3.82

3.40
4.51

$

$

$
$

21.46

1.99

1.59
2.00

Average Market On-Peak Power
Prices ($MWh) (b):
PJM West Hub
AEP Dayton Hub
NYISO Zone C
Massachusetts Hub
Indiana Hub
Northern Illinois Hub

Year Ended December 31,

2021

2020

$
$
$
$
$
$

45.62
44.88
35.59
51.81
48.62
41.15

$
$
$
$
$
$

24.55
24.49
19.37
26.57
26.77
22.47

____________
(a) Reflects the average of daily quoted prices forff
(b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we

the periods presented and does not reflect costs incurred by us.

realized.

The folff

lowing table presents changes in net income (loss) and Adjusted EBITDA forff

the year ended December 31, 2021

compared to the year ended December 31, 2020.

l
) change in revenue net of fueff

Favorable/(unfavorablea
Winter Storm Uri impact
Favorable/(unfavorablea
Favorablea
administrative expenses
Other (including other income and other deductions) (a)
ed EBITDA

/(unfavorable) change in selling, general and

) change in other operating costs

Change in Adjust

d

/(unfavorable) change in depreciation and amortization

Favorablea
Change in unrealized net losses on hedging activities
Other, including impairment of long-lived and other assets
Generation plant retirement expenses
Fresh start/purcha
Transition and merger expenses

se accounting impacts

/

Winter Storm Uri impact (ERCOT defaul
Loss on disposal of investment in NELP

ff

t uplu ift and legal disputes)

Change in Net income (loss)

____________

Year Ended December 31, 2021 Compared to 2020

Texas

East

West

Sunset

$

(447) $

(1,535)
19

—
81
(1,882) $
(136)
(1,830)
25
—
6
2

(457)
—
(4,272) $

$

$

(175) $
50
8

10
(5)
(112) $
23
(640)
(5)
—
96
1

—
29
(608) $

$

$

34
—
(7)

(6)
(1)
20
(41)
(28)
—
—
—
—

—
—
(49) $

(178)
17
(39)

8
10
(182)
(6)
(235)
329
25
71
—

(1)
—
1

(a) For the year ended December 31, 2021, includes insurance proceeds of $80 million in the Texas segment and $7 million

in the Sunset segment.

The change in Texas segment results was primarily driven by the Winter Storm Uri impacts, including the need to procure
gas-fueled power plants driven
power in ERCOT at market prices at or near the price cap due to lower output from our natural
by natural
gas-fueled power plants due to extremely high fuel costs,
t
t
and, to a lesser extent, operational challenges associated with Winter Storm Uri, and unrealized hedging losses in the year
ended December 31, 2021 versus unrealized hedging gains in the year ended December 31, 2020, partially offset by insurance
proceeds received in 2021.

gas deliverability issues, lower margins from our natural

t

The change in East segment results was driven by lower revenue net of fuel and larger unrealized hedging losses in the
year ended December 31, 2021 versus the year ended December 31, 2020, partially offset by loss on disposal of equity method
investment in NELP for 100% ownership of NJEA (see Note 21 to the Financial Statements) in 2020.

73

The change in West segment results was driven by larger unrealized hedging losses in year ended December 31, 2021
versus the year ended December 31, 2020, partially offset by higher realized prices through hedging activities and plant
optimization efforts.

The change in Sunset segment results was driven by larger unrealized hedging losses in year ended December 31, 2021
versus the year ended December 31, 2020 and lower margins due to lower realized prices and higher operating costs, partially
offset by higher impairment of long-lived assets generation plant retirement expenses related to our Joppa/EEI, Kincaid and
Zimmer coal generation facilities in 2020.

Asset Closull

re Segment — Year Ended December 31, 2021 Compared

m

Operating revenues
Operating costs
Depreciation and amortization
Selling, general and administrative expenses

Operating loss

Other income
Other deductions
Interest expense and related charges

Income (loss) before income taxes

Net loss

Adjusted EBITDA

to Year Ended December 31, 2020

Year Ended December 31,

2021

2020

Favorable
(Unfavorable)
Change

$

$

$

— $
(30)
—
(26)
(56)
35
—
(1)
(22)

(22) $

(33) $

$

3
(63)
(22)
(27)
(109)
10
(2)
—
(101)

(101) $

(81) $

(3)
33
22
1
53
25
2
(1)
79

79

48

Operating costs for the years ended December 31, 2021 and 2020 included ongoing costs associated with the
decommissioning and reclamation of retired plants and mines. The year ended December 31, 2021 includes a gain on the
settlement of rail transportation disputes (see Note 21 to the Financial Statements).

Energy-Relatell

MM
d ComCC modityii Contracts and Mark-to-M

MM

arket

Activitiii es

The tablea

below summarizes the changes in commodity contract assets and liabilities for the years ended December 31,
2021 and 2020. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $759
million in unrealized net losses and $231 million in unrealized net gains forff
the years ended December 31, 2021 and 2020,
respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

Year Ended December 31,

2021

2020

$

Commodity contract net liability at beginning of period
Settlements/termination of positions (a)
Changes in fair value of positions in the portfolio (b)
Other activity (c)
Commodity contract net liability at end of period
____________
(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/ttt ermination (offsets realized
gains and losses recognized in the settlement period). The years ended December 31, 2021 and 2020 also include
reversals of $3 million and $12 million, respectively, of previously recorded unrealized losses related to commodity
contracts acquired in the Merger, Crius Transaction and Ambit Transaction. The year ended December 31, 2020 includes
reversals of $1 million of previously recorded unrealized losses related to Vistra beginning balances. 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.

(75) $
(295)
(464)
(32)
(866) $

(279)
(14)
245
(27)
(75)

$

(b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in faiff

r 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.

74

(c) 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 Ttt

presents the net commodity contract liabia lity arising from recognition of fair
values at December 31, 2021, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

ell — The following tablea

ablTT

Source of fair value
Prices actively quoted
Prices provided by other external sources
Prices based on models

Total

Maturity dates of unrealized commodity contract net liability at December 31, 2021

Less than
1 year

1-3 years

$

$

(631)
352
(72)
(351)

$

$

(116)
(113)
(83)
(312)

4-5 years
2
1
(108)
(105)

$

$

$

$

Excess of
5 years

— $
(1)
(97)
(98)

$

Total

(745)
239
(360)
(866)

FINANCIAL CONDITION

s
Operatingii Cash FlowFF

Year Ended December 31, 2021 Comparem

d to Year Ended December 31, 2020 — Cash used in operating activities totaled
$206 million in the year ended December 31, 2021 compared to cash provided by operating activities of $3.337 billion in the
year ended December 31, 2020. The unfavorablea
change of $3.543 billion was primarily driven by lower cash from operations
due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties. Cash margin deposits posted were
gas and coal forward
driven by net pre-tax unrealized losses on commodity hedging transactions reflecting power, natural
market curves that moved up during the year ended December 31, 2021.

ff

t

Depreciation and amortization — Depreciation and amortization expense reported as a reconciling adjustment in the
consolidated statements of cash flows exceeds the amount reported in the consolidated statements of operations by $297
million, $311 million and $236 million for the year ended December 31, 2021, 2020 and 2019, respectively. The difference
represented amortization of nuclear fuel
costs in the consolidated statements of operations consistent
ff
with industry practice, and amortization of intangible net assets and liabilities that are reported in various other consolidated
statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees.

, which is reported as fuel

ff

sw
Investingii Cash FlowFF

Year Ended December 31, 2021 Compared to YearYY

Ended December 31, 2020 — Cash used in investing activities totaled
$1.153 billion and $1.572 billion in the years ended December 31, 2021 and 2020, respectively. Capita
al expenditures totaled
$1.033 billion and $1,259 million in the years ended December 31, 2021 and 2020, respectively, and. consisted of the
following:

, including LTSA prepayments

t

al expenditures

Capita
Nuclear fuel purchases
Growth and development expenditures
t

al expenditures

Capita

$

Year Ended December 31,

2021

2020

549 $
44
440
1,033 $

770
88
401
1,259

Cash used in investing activities in the year ended December 31, 2021 and 2020 also reflected net purchases of
environmental allowances of $213 million and $339 million, respectively. In the year ended December 31, 2021 and 2020, we
received insurance proceeds of $89 million and $35 million, respectively.

75

Financing Cash Flowsw

Year Ended December 31, 2021 Comparem

ncing activities
totaled $2.274 billion in the year ended December 31, 2021 and cash used in financing activities totaled $1.796 billion in the
year ended December 31, 2020. The change was primarily driven by:

Ended December 31, 2020 — Cash provided by finaff

d to YearYY

•
•
•

•
•
•

proceeds of $1.975 billion from the issuance of preferred stock in 2021;
the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in 2021;
$500 million in cash received fromff
in 2021;
redemption of $747 million principal amount of outstanding of Vistra unsecured senior notes in 2020;
net repayment of $350 million in short-term borrowings under the Revolving Credit Facility in 2020; and
repayment of $100 million of term loans under the Vistra Operations Credit Facilities in 2020;

the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022

partially offset by:

• $471 million in cash paid for share repurchases in 2021; and
• net repayments of $300 million under the Receivables Facility in 2021 compared to net repayments of $150 million in

2020.

Debt Activityii

See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 11 to the

Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.

ll
Available

Liquidi

tyii

ii

The following tabla e summarizes changes in availablea

liquidity for the year ended December 31, 2021:

Cash and cash equivalents
Vistra Operations Credit Facilities — Revolving Credit Facility
Vistra Operations — Alternate Letter of Credit Facility

Total available liquidity (a)

December 31, 2021
1,325
$
1,254
—
2,579

$

December 31, 2020
406
$
1,988
5
2,399

$

$

$

Change

919
(734)
(5)
180

____________
(a) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See

Note 10 to the Financial Statements for detail on our accounts receivablea

financing.

a

The $180 million increase in available liquidity for the year ended December 31, 2021 was primarily driven by proceeds
of $1.975 billion from the issuance of preferred stock in 2021, cash received from the issuance of $1.250 billion principal
amount of Vistra Operations senior unsecured notes in May 2021 and $500 million in cash received from the sale of a portion
ity that cleared for Planning Years 2021-2022, partially offset by cash used in operations, including higher
of the PJM capac
cash margin deposits posted with third parties, $1.033 billion of capita
al expenditures (including LTSA prepayments, nuclear
a $734 increase in letters of credit outstanding under the Revolving Credit
fuel and development and growth expenditures),
t
Facility, $290 million in dividends paid to stockholders, $471 million in cash paid forff
share repurchases, $300 million in net
ncing facilities and the maturity of a $250 million Alternate LOC Facility.
cash repayments under the accounts receivable finaff
Additionally, in February 2022, we entered into a $1.0 billion senior secured commodity-linked revolving credit facility (the
Commodity-Linked Facility) (see Note 11 to the Financial Statements).

Based upon our current internal finaff

ncial forecasts, we believe that we will have sufficient liquidity to fund our
anticipated cash requirements through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted
toward the second half of the year.

If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, such as a
result of Winter Storm Uri, the Company believes it would have additional alternatives to maintain access to liquidity, including
drawing upon available liquidity, accessing additional sources of capital or reducing capita
al expenditures, planned voluntary
debt repayments or operating costs.

76

The maturities of our long-term debt are relatively modest until 2023. Interest payments on long-term debt are expected
to total approximately $499 million in 2022, $946 million in 2023-2024, $753 million in 2025-2026 and $372 million
thereafter. See Note 11 to the Financial Statements forff

details of our long-term debt maturities.

Our obligations under commodity purchase and services agreements, including capac

and
natural
gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase
t
commitments, are expected to total approximately $1.850 billion in 2022, $1.250 billion in 2023-2024, $700 million in
2025-2026 and $585 million thereafter. See Note 12 to the Financial Statements forff maturities of lease liabia lities and Note 13
to the Financial Statements for commitments related to long-term service and maintenance contracts.

ity payments, nuclear fuel

a

ff

Capital

ii Expenditures

Estimated 2022 capita

al expenditures and nuclear fuel

ff

purchases as of November 5, 2021 total approximately $1.814

billion and include:

•
•
•
•
•

$1.002 billion for solar and energy storage development;
$570 million for investments in generation and mining facilities;
$117 million for nuclear fuel purchases;
$72 million for information technology and other corporate investments; and
$53 million for other growth expenditures.

Liquidit

y Ett

ffecE

ii

ts of Commodity Htt

edgiHH

ngii

and Trading Activitiii es

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 11 to the Financial
Statements for discussion of the Vistra Operations Credit Facilities.

ff

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
al and other business purposes, including reducing borrowings under credit facilities, or is required to be
used for working capita
al and other corporate purposes. With respect
deposited in a separate account and restricted from being used for working capita
letters of credit for such cash collateral. In
to over-the-counter transactions, counterparties generally have the right to substitutet
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.

ff

t

As of December 31, 2021, we received or posted cash and letters of credit for commodity hedging and trading activities as

follows:

•
•

•

•

$1.263 billion in cash has been posted with counterparties as compared to $257 million posted at December 31, 2020;
$39 million in cash has been received from counterparties as compared to $33 million received at December 31,
2020;
$1.558 billion in letters of credit have been posted with counterparties as compared to $878 million posted at
December 31, 2020; and
$35 million in letters of credit have been received from counterparties as compared to $18 million received at
December 31, 2020.

See Collateral Support Obligati

i

ons below forff

information related to collateral posted in accordance with the PUCT and

ISO/RTO rules.

77

Income Tax Payma

entstt

In the next 12 months, we do not expect to make federal income tax payments dued
a

to Vistra's loss position in 2021 and use
mately $35 million in state income tax payments, offset by $11 million in

We expect to make approxi

rr
of NOL carryforwards.
state tax refunds, and less than $1 million in TRA pRR

ayments in the next 12 months.

For the year ended December 31, 2021, there were no federal income tax payments, $52 million in state income tax

payments, $2 million in state income tax refunds and $2 million in TRA payments.

Capitalization

Our capita

alization ratios consisted of 56% and 52% long-term debt (less amounts due currently) and 44% and 48%
stockholders' equity at December 31, 2021 and 2020, respectively. Total long-term debt (including amounts due currently) to
capita

alization was 56% and 53% at December 31, 2021 and 2020, respectively.

Finaii ncial CoveCC

nantstt

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 appl
icable 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, 2021, we were in compliance with this financ

ial covenant.

a

ff

See Note 11 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit

Facilities.

ll
Collat

tt
ertt al Support Obligat
ions

ll

ff

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
lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities)
effectively a first
that contractually enablea
ien 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 forff 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.

s the RCT to be paid (up to $975 million) before the other first-l

ff

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to returnt

customer
deposits, if necessary. Under these rules, at December 31, 2021, Vistra has posted letters of credit in the amount of $74 million
with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the
markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $420 million in the form
of letters of credit, $20 million in the form of a surety bond and $1 million of cash at December 31, 2021 (which is subject to
daily adjustmd

ents based on settlement activity with the ISOs/RTOs).

//
Material Cross-Default/
Acc

e

ll
elerati

on Provisions

lure
Certain of our contractual arrangements contain provisions that could result in an event of default if there were a faiff
under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments
due. Such provisions are referre

d to as "cross-default" or "cross-acceleration" provisions.

ff

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 under such facilities, which totaled
approximately $2.54 billion at December 31, 2021.

78

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap aa

greements 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 equal to or above a
agreement that results in the acceleration of such debt, would give such counterparty under
threshold defined in the applicablea
these hedging agreements the right to terminate its hedge or interest rate swap a
greement with Vistra Operations (or its
a
applicable subsidiary) and require all outstanding obligations under such agreement to be settled.

Under the Vistra Operations Senior Unsecured Indentures

a default
under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary 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 Vistra Operations Senior Unsecured Notes, the Senior Secured
Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Alternate LOC Facilities, and other current or future
documents evidencing any indebtedness for borrowed money by the applicablea
borrower or issuer, as the case may be, and the
applicable Guarantor Subsidiaries party thereto.

and the Vistra Operations Senior Secured Indenture,

t

t

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 brr

y contract.

The Receivablea

s Facility contains a cross-default provision. The cross-default provision applies, among other instances, if
TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle, each indirect subsidiaries of Vistra
and originators under the Receivablea
s Facility (Originators), 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 or any of the other
Originators, in a principal amount of at least $50 million, after the expiration of any applicable grace period, 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 dued
If this cross-default provision is triggered, a
termination event under the Receivables Facility would occur and the Receivables Facility may be terminated.

before its stated maturity.

The Repurchase Facility contains a cross-default provision. The cross-default provision applies, among other instances,
if an event of default (or similar event) occurs under the Receivablea
s Facility or the Vistra Operations Credit Facilities. If this
cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility
may be terminated.

Under the Alternate LOC Facilities, a defauff

lt under any document evidencing indebtedness for borrowed money by Vistra
Operations or any Guarantor Subsidiary 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 Alternate LOC
Facilities.

Under the Secured LOC Facilities, a defauff

lt under any document evidencing indebtedness for borrowed money by Vistra
Operations or any Guarantor Subsidiary 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 Secured LOC
Facilities.

Under the Commodity-Linked Facility, a default under any document evidencing indebtedness for borrowed money by
Vistra Operations or any Guarantor Subsidiary 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
Commodity-Linked Facility.

s
Guaranteett

See Note 13 to the Financial Statements forff

discussion of guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 13 to the Financial Statements forff

discussion of commitments and contingencies.

79

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

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 because of changes in
tors such as commodity prices, interest rates and counterparty credit. Our exposure
market conditions that affect economic facff
tors, including the size, duration and composition of our energy and financial portfolio,
to market risk is affected by several facff
as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swapsa
to hedge
debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity
prices.

t
Riskii Oversigh

rr

We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive
energy business within limitations establia
shed 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
, market price validation and reporting, and portfolio valuation and reporting, including mark-to-market,
transaction capture
VaR and other risk measurement metrics.

a

Vistra has a risk management organization that enforces applicablea

risk limits, including the respective policies and

procedures to ensure complim ance with such limits, and evaluates the risks inherent in our businesses.

Commoditdd y Ptt

ricPP e 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.

t

t

t

In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-
ncial contracts and bilateral contracts with
term contracts for physical delivery, exchange-traded and over-the-counter finaff
customers. Activities include hedging, the structuring
arrangements and proprietary trading. We
of long-term contractual
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.

t

t

VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio
loss given a specified
under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential forff
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
io's value based on assumed market conditions for liquid markets. The use of this method requires
estimate changes in a portfolff
a number of key assumptim ons, 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 tablea

below details a VaR measure related to various portfolios of contracts.

80

VaR faa

orff Underlying Generation Assets and Energy-Rr

d ConCC tracts — This measurement estimates the potential loss
elatell
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. The forward period covered by this calculation includes the current and
subsequent calendar year at the time of calculation.

Month-end average VaR
Month-end high VaR
Month-end low VaR

Year Ended December 31,

2021

2020

$
$
$

424
684
222

$
$
$

234
361
164

The VaR risk measures in 2021 were primarily comparablea
measure in 2021 is driven by a larger net open position, higher forwa
ff
compared to the prior year.

to the prior year. The increase in month-end high VaR risk
rd prices and an increase in market implied volatility as

Interett

st Rate Riskii

The following tablea

provides information concerning our financial instruments at December 31, 2021 and 2020 that are
sensitive to changes in interest rates. Debt amounts consist of the Vistra Operations Credit Facilities. See Note 11 to the
Financial Statements for furff

ther discussion of these financial instruments.

Expected Maturity Date

2022

2023

2024

2025

2026

2021
Total
Carrying
Amount

2021
Total
Fair
Value

2020
Total
Carrying
Amount

2020
Total
Fair
Value

There-
after

$ 29

$

28

$ 29

$2,457

$ — $ — $2,543

$ 2,518

$2,572

$ 2,565

1.85 % 1.85 % 1.85 % 1.85 %

— % — % 1.85 %

1.90 %

Long-term debt,
including current
maturities (a):
Variablea
rate
debt amount
Average interest
rate (b)

Debt swapped to
fixed (c):

Notional amount $ — $2,300
Average pay
rate
Average receive
rate

3.77 % 4.10 % 4.75 % 4.77 % 4.77 % — %

1.86 % 2.24 % 2.98 % 3.01 % 3.01 % — %

$ — $ — $2,300

$ — $4,600

$4,600

(a) Unamortized premiums, discounts and debt issuance costs are excluded fromff
(b) The weighted average interest rate presented is based on the rates in effecff
(c)

the table.

t at December 31, 2021.

Interest rate swaps have maturity dates through July 2026. Excludes $2.12 billion of debt swapped
matched against the terms of $2.12 billion of debt swapped
such swapsa

to variable that is
to fixed that effectively fix the out-of-the-money position of

(see Note 11 to the Financial Statements).

a

a

As of December 31, 2021, 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 $2 million taking
into account the interest rate swapsa

discussed in Note 11 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 16 to the Financial Statements for furthe
r discussion
of this exposure.

ff

81

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
$2.357 billion at December 31, 2021.

As of December 31, 2021, Retail segment credit exposure totaled approxi

mately $900 million of primarily trade accounts
receivable. Cash deposits and letters of credit held as collateral for these receivables totaled $60 million, resulting in a net
exposure of $840 million. Allowances forff
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.

a

As of December 31, 2021, aggregate Texas, East and Sunset segments credit exposure totaled $1.457 billion including
$687 million related to derivative assets and $770 million of accounts receivable, after taking into account master netting
agreement provisions but excluding collateral impacts.

Including collateral posted to us by counterparties, our net Texas, East and Sunset segments exposure was $1.390 billion,
that presents the distribution of credit exposure by counterparty credit quality at December 31,
as seen in the following tablea
2021. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on
assets.

Investment grade
Below investment grade or no rating

Totals

Exposure
Before Credit
Collateral
947
510
1,457

$

$

$

$

Credit
Collateral

Net
Exposure
923
467
1,390

24
43
67

$

$

Significant (i.e., 10% or greater) concentration of credit exposure exists with one counterparty, which represented an
aggregate $619 million, or 45%, of the total net exposure. We view exposure to this counterparty to be within an acceptablea
level of risk tolerance due to the counterparty's credit ratings, the counterparty's market role and deemed creditworthiness and
the importance of our business relationship with the counterparty. 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

in the financial statements and are excluded from the detail above.
favorablea

a

considering current market conditions and therefore represent economic risk if the counterparties do not perform.

commitments are not marked-to-market
Such contractual commitments may contain pricing that is

t

82

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, capita
al 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 assumptim ons, any such
forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion under
Item 1A. Riskii Factors and Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations in
this annual report on Form 10-K and the following important factors, among others, that could cause our actual results to differ
materially fromff

those projected in or implied by such forward-looking statements:

al allocation, capita

ll

•
•
•

•

•
•
•
•

•

•

•
•

▪

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 legislaturt es 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 l
aws and policies, including the Coal Combustion
Residuad ls Rule, 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 negatively impact our financial results or stock price;
legal and administrative proceedings and settlements;
general industry trends;
economic conditions, including the impact of any recession or economic downturn;
investor sentiment relating to climate change and utilization of fossil fuels
reduce demand for,
the severity, magnitude
our results of operations, financial condition and cash flows;
the severity, magnitude
and duration of extreme weather events (including Winter Storm Uri), drought and limitations
on access to water, and other weather conditions and natural phenomena, contingencies and uncertainties relating
thereto, most of which are diffiff cult to predict and many of which are beyond our control, and the resulting effects on
our results of operations, financial condition and cash flows;
acts of sabotage, wars or terrorist or cybersecurity threats or activities;
risk of contract performance claims by us or our counterparties, and risks of, or costs associated with, pursuing or
defending such claims;

or increase potential volatility in the market price of, our common stock;
t

and duration of pandemics, including the COVID-19 pandemic, and the resulting effects on

in connection with power generation could

ff

ff

ff

ff

t

t

t

83

•
•
•
•

•
•
•

•

•

•

•
•

•
•

•
•
•
•
•

•

•

•

•
•

•
•
•
•
•
•
•

•

•

•
•

•

•

t

t

t

t

ff

ff

ff

a

gas;

laws;

s fromff

al expenditures;

gas, market heat

serve customers;

gas inventories and transportation and

al market conditions and the potential

commodity prices, including the price of natural

ies to reduce congestion and improve busbar power prices;

ce and regulators regarding our compliance with applicablea

counterparties in the amount or at the time expected, if at all;

to our competitors;
ity procurement processes in

oil and other refined products;
t

d outage risk, including managing risk associated with Capacity Performance in PJM and

nd assumptim ons about the benefits of state- or federal-based subsidies to our market competition, and the

our ability to collect trade receivablea
our ability to attract, retain and profitablya
restrictions on competitive retail pricing or direct-selling businesses;
adverse publicity associated with our retail products or direct selling businesses, including our ability to address the
marketplat
changes in wholesale electricity prices or energy commodity prices, including the price of natural
changes in prices of transportation of natural gas, coal, fuel
sufficiency of, access to, and costs associated with coal, fuel oil, and natural
storage thereof;
changes in the ability of counterparties and suppliers to provide or deliver commodities, materials, or services as
needed;
beliefs aff
corresponding impacm ts on us, including if such subsidies are disproportionately availablea
the effects of, or changes to, market design and the power, ancillary services, and capac
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 unfavorablea
rates and interest rates;
population growth or decline, or changes in market supply or demand and demographic patterns;
our ability to mitigate force
performance incentives in ISO-NE;
efforts to identify opportunit
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 capita
commercial bank market and capita
international credit markets;
access to capital, the attractiveness of the cost and other terms of such capita
refinancing efforts,
our ability to maintain prudent financial leverage and achieve our capita
initiatives and objectives;
our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our
debt obligations;
our expectation that we will continue to pay a comparable cash dividend on a quarterly basis;
our ability to implement and successfully execute upon
and integration of mergers, acquisitions and/or joint venturet
t
divestitures
projects;
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 facff
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 availabila
a
potential adverse effects if labor
independent contractor status;
changes in assumptim ons 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 liabia lity 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 businesses acquired by Vistra and our ability to successfully
a
capture

our strategic and growth initiatives, including the completion
activity, the identification and completion of sales and
activity, and the completion and commercialization of our other business development and construction

ity of qualified personnel, and the
disputes or grievances were to occur or changes in laws or regulations relating to

the full amount of projected operational and financial synergies relating to such transactions; and

tors affecting our liquidity position and financial condition;

including availability of funds in capia tal markets;

al allocation, performance, and cost-saving

al and the success of financing and

impact of disruptions in U.S. and

u

t

84

•

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 facff
tors 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 fromff
those
contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking
statements.

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 firff ms 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
, but do not guarantee the accuracy and completeness of such information. While we believe that
sources believed to be reliablea
, we have not independently investigated or verified the
each of these studies, publications, reports and other sources is reliablea
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 assumptim ons
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.

85

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Vistra Corp.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Vistra Corp. and its subsidiaries (the “Company”) as of
December 31, 2021 and 2020, the related consolidated statements of operations, consolidated statements of comprehensive
income (loss), consolidated statements of cash flows, and consolidated statement of changes in equity, for each of the three
years in the period ended December 31, 2021, and the related notes and the schedule listed in the Index at Item 15(b)
(collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material
respects, the financ
ial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally
accepted in the United States of America.

ff

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, 2021, based on criteria established in
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
e
Internal Control—Integrated
Commission and our report dated February 2rr
5, 2022, expressed an unqualified opinion on the Company’s internal control over
financial reporting.

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 PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicablea
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 freff e of material misstatement, whether dued
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 finff ancial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that
were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that
are material to the finaff
ncial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and
we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on
the accounts or disclosures to which they relate.

Tax Receivable Agreement Obligation — Referff

to Notes 1 and 8 to the financial statements

Critical Audit MatMM ter Description

ights holders based on cash savings in income tax resulting fromff

The Company has a tax receivable agreement (TRA) obligation that requires the Company to make annual payments to the
a step up in the tax basis of certain assets upon
TRA rRR
bligation is based on the discounted amount of forecasted
emergence from bankruptcy in 2016. The carrying value of the TRA oRR
payments to the TRA rRR
bligation requires management to make
ast of taxable income for a period of approximately 35 years.
significant estimates and assumptim ons in preparing its forec
Changes to either the estimated timing or amount of expected TRA pRR
ayments impact the carrying value of the obligation. As of
December 31, 2021, the carrying value of the TRA oRR

ights holders. Determining the carrying value of the TRA oRR

bligation totaled $395 million.

ff

86

Given the significant judgements made by management to estimate the TRA oRR
evaluate the reasonablea
a high degree of auditor judgement and an increased extent of effort,

bligation, performing audit procedures to
ness of management’s estimate and assumptions related to the estimated future taxable income required

including the need to involve our income tax specialists.

ff

How the Critical Audit MatMM ter WasWW Addressed in thett Audit

Our audit procedures related to the evaluation of estimated future

ff

taxable income included the folff

lowing, among others:

• We tested the effectiveness of controls over management’s determination of the TRA oRR

bligation carrying amount,

including controls over developing estimated futuret

taxablea

income.

• With the assistance of our income tax specialists, we evaluated the following elements in testing management’s

estimated future

ff

taxable income:

◦

◦

The application of tax laws and regulations

Future reversals of existing temporary differences, including the timing and amount of loss carryforwards

• We evaluated the reasonableness of management’s estimates of future taxable income by comparing the estimates to:

◦

◦

◦

Historical taxable income

Internal communications to management and the Board of Directors

Forecasted information included in the Company's press releases as well as in analyst and industry reports forff
Company

the

• We assessed the consistency of future

ff

taxable income with evidence obtained in other areas of the audit.

Fair Value Measurements — Level 3 Derivative Assets and Liabilities — Referff
statements

to Notes 1 and 15 to the financial

Critical Audit MatMM ter Description

The Company has assets and liabilities whose fair values are based on complex proprietary models and/or unobservable inputs.
These financial instruments can span a broad array of product types and generally include (1) electricity purchases and sales
gas options;
that include power and heat rate positions; (2) physical electricity options, spread options, swaptia
(3) forward purchase contracts of congestion revenue rights and financial transmission rights; and (4) contracts for natural
gas,
coal, and environmental allowances. Under accounting principles generally accepted in the United States of America, these
financial instruments are generally classified as Level 3 derivative assets or liabilities. As of December 31, 2021, the fair value
of the Level 3 derivative assets and liabilities totaled $442 million and $802 million, respectively.

ons, and natural

t

t

Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of Level 3 derivative
assets and liabia lities, performing audit procedures to evaluate the reasonableness of the fair value of Level 3 derivative assets
and liabia lities required a high degree of auditor judgment and an increased extent of effort, including the need to involve our
energy commodity fair value specialists who possess significant quantitative and modeling expertise.

How the Critical Audit MatMM ter WasWW Addressed in thett Audit

Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the foll
among others:

ff

owing,

• We test ded hthe effectiiveness of cont

lrols over d iderivatiive asset a dnd lili biabilili yty

pricprice verifiifica ition of ilillili

idquid

iprice curves.

lvaluatiions, iincl di

ludi gng cont

lrols

lrelat ded to

• We bobtaiinedd thhe Compa yny's com lplete lili
dunderstanding

31, 2021, to co finfirm our

isti gng of d iderivatiive assets

dand lili biabilili ities
nding.
nding of hthe tyypes of iinstruments outstanding.

dand

lrelat ded f ifair v lalues as of Dece bmber

• We assessedd thhe consiistency by byy whi hhich managgement hhas

87

appliiedd signi

ignifificant

l

unobse
b

rvable v lalua ition as

bl

sumptions.
i

•

i hWith hthe a issistance of our ene gyrgy com dimodi yty f ifair v lalue spe ici laliists, we ddevello dped i dinde
lvalue of a sam lple of Level

l 3 deriiva itive iinstruments a dnd comparedd our es itimates to thhe Compa yny's

dpendent es itimates of thhe f ifair
iestimates.

d

/s/ Deloitte & Touche LLP

Dallas, Texas
February 25, 2022

We have served as the Company's auditor since 2002.

88

VISTRA CORP.
CONSOLIDATED STATEMENTS OF OPERATRR IONS
(Millions of Dollars, Except Per Share Amounts)

Operating revenues (Note 5)
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Impairment of long-lived and other assets
Operating income (loss)
Other income (Note 21)
Other deductions (Note 21)
Interest expense and related charges (Note 21)
Impacts of Tax Receivablea
Agreement (Note 8)
Equity in earnings of unconsolidated investment (Note 21)
Income (loss) before income taxes
Income tax (expense) benefit (Note 7)
Net income (loss)
Net (income) loss attributablea
Net income (loss) attributablea
Weighted average shares of common stock outstanding:

to noncontrolling interest
to Vistra

Basic
Diluted

Net income (loss) per weighted average share of common stock
outstanding:
Basic
Diluted

See Notes to the Consolidated Financial Statements.

Year Ended December 31,

2021

2020

2019

$

12,077
(9,169)
(1,559)
(1,753)
(1,040)
(71)
(1,515)
140
(16)
(384)
53
—
(1,722)
458
(1,264)
(10)
(1,274) $

11,443
(5,174)
(1,622)
(1,737)
(1,035)
(356)
1,519
34
(42)
(630)
5
4
890
(266)
624
12
636

$

$

11,809
(5,742)
(1,530)
(1,640)
(904)
—
1,993
56
(15)
(797)
(37)
16
1,216
(290)
926
2
928

482,214,544
482,214,544

488,668,263
491,090,468

494,146,268
499,935,490

(2.69) $
(2.69) $

1.30
1.30

$
$

1.88
1.86

$

$

$
$

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)

Net income (loss)
Other comprehensive income (loss), net of tax effects:

Year Ended December 31,

2021

2020

2019

$

(1,264) $

624

$

926

Effects related to pension and other retirement benefit obligations (net of
tax expense (benefit) of $9, ($5) and ($4))

Total other comprehensive income (loss)
Comprehensive income (loss)
Comprehensive income (loss) attributablea
Comprehensive income (loss) attributablea

to noncontrolling interest
to Vistra

32
32
(1,232)
(10)

(18)
(18)
606
12

$

(1,242) $

618

$

(8)
(8)
918
2

920

See Notes to the Consolidated Financial Statements.

89

VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)

Cash flowff

s — 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
Impairment of long-lived and other assets
Loss on disposal of investment in NELP
Unrealized net (gain) loss from mark-to-market valuations of
commodities
Unrealized net (gain) loss from mark-to-market valuations of interest
rate swaps
Change in asset retirement obligation liability
Asset retirement obligation accretion expense
Impacts of Tax Receivablea
Bad debt expense
Stock-based compensation
Other, net

Agreement

Changes in operating assets and liabilities:

Accounts receivablea — trade
Inventories
Accounts payable — trade
Commodity and other derivative contractual assets and liabia lities
Margin deposits, net
Uplift securitization proceeds receivablea
Accrued interest
Accrued taxes
Accrued employee incentive
Tax Receivable Agreement payment
Asset retirement obligation settlement
Major plant outage deferral
Other — net assets
Other — net liabilities

from ERCOT

Cash provided by (used in) operating activities

Cash flows — investing activities:
t

al expenditures,

including nuclear fuel purchases and LTSA

Capita
prepayments
Ambit acquisition (net of cash acquired)
Crius acquisition (net of cash acquired)
Proceeds from sales of nuclear decommissioning trust
Investments in nuclear decommissioning trust fund securities
Proceeds from sales of environmental allowances
Purchases of environmental allowances
Insurance proceeds
Proceeds from sale of assets

r

fund securities

90

Year Ended December 31,

2021

2020

2019

$

(1,264) $

624

$

926

2,050
(475)
71
—

759

(134)
(5)
38
(53)
110
47
41

(228)
(100)
402
32
(1,000)
(544)
13
(20)
(68)
(2)
(88)
2
(27)
237
(206)

(1,033)
—
—
483
(505)
392
(605)
89
30

2,048
230
356
29

1,876
281
—
—

(231)

(696)

155
7
43
(5)
110
65
(22)

(33)
(59)
(40)
27
(20)
—
(20)
22
39
—
(118)
2
219
(91)
3,337

(1,259)
—
—
433
(455)
165
(504)
35
24

220
(48)
53
37
82
47
(12)

(88)
(44)
(221)
98
170
—
80
(4)
1
(2)
(121)
(19)
(22)
142
2,736

(713)
(506)
(374)
431
(453)
197
(322)
23
6

VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)

Year Ended December 31,

2021

2020

2019

(6)
(1,717)

—
6,507
(7,109)
—
—
—
111
650
(300)
(203)
(656)
(243)
6
(1,237)

(218)
693
475

Other, net

Cash used in investing activities

Cash flows — finaff

ncing activities:

Issuances of preferred stock
Issuances of long-term debt
Repayments/repurchases of debt
Borrowings under Term Loan A
Repayment under Term Loan A
Proceeds from forward capaa
Net borrowings/(payments) under accounts receivable finaff
Borrowings under Revolving Credit Facility
Repayments under Revolving Credit Facility
Debt tender offer and other financing fees
Share repurchases
Dividends paid to stockholders
Other, net

city agreement

ncing

Cash provided by (used in) finaff

ncing activities

(4)
(1,153)

2,000
1,250
(381)
1,250
(1,250)
500
(300)
1,450
(1,450)
(13)
(471)
(290)
(21)
2,274

(11)
(1,572)

—
—
(1,008)
—
—
—
(150)
1,075
(1,425)
(17)
—
(266)
(5)
(1,796)

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

915
444
1,359

$

$

(31)
475
444

$

See Notes to the Consolidated Financial Statements.

91

VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)

December 31,

2021

2020

Current assets:

ASSETS

Cash and cash equivalents
Restricted cash (Note 21)
Trade accounts receivablea — net (Note 21)
Income taxes receivable
Inventories (Note 21)
Commodity and other derivative contractual assets (Note 16)
Margin deposits related to commodity contracts
Uplift securitization proceeds receivabla e fromff
Prepaid expense and other current assets

ERCOT (Note 1)

Total current assets
Restricted cash (Note 21)
Investments (Note 21)
Operating lease right-of-use assets (Note 12)
Property, plant and equipment — net (Note 21)
Goodwill (Note 6)
Identifiable intangible assets — net (Note 6)
Commodity and other derivative contractual assets (Note 16)
Accumulated deferred income taxes (Note 7)
Other noncurrent assets
Total assets

LIABILITIES AND EQUITY

Current liabilities:

Accounts receivablea
financing (Note 10)
Long-term debt due currently (Note 11)
Trade accounts payable
Commodity and other derivative contractual liabila
Margin deposits related to commodity contracts
Accrued income taxes
Accrued taxes other than income
Accrued interest
Asset retirement obligations (Note 21)
Operating lease liabilities (Note 12)
Other current liabilities

ities (Note 16)

currently (Note 11)

Total current liabilities
Long-term debt, less amounts dued
Operating lease liabilities (Note 12)
Commodity and other derivative contractual liabila
Accumulated deferred income taxes (Note 7)
Tax Receivablea
Asset retirement obligations (Note 21)
Other noncurrent liabilities and deferred credits (Note 21)

Agreement obligation (Note 8)

ities (Note 16)

Total liabilities

92

$

$

$

1,325
21
1,397
15
610
2,513
1,263
544
195
7,883
13
2,049
40
13,056
2,583
2,146
250
1,302
361
29,683

$

$

— $
254
1,515
3,023
39
—
207
143
104
5
553
5,843
10,477
38
804
—
394
2,346
1,489
21,391

406
19
1,279
—
515
748
257
—
205
3,429
19
1,759
45
13,499
2,583
2,446
258
838
332
25,208

300
95
880
789
33
16
210
131
103
8
471
3,036
9,235
40
624
1
447
2,333
1,131
16,847

VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)

Commitments and Contingencies (Note 13)
Total equity (Note 14):

Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation
preference — $1,000; shares outstanding: December 31, 2021 — 1,000,000;
December 31, 2020 — zero); Series B (liquidation preference — $1,000; shares
outstanding: December 31, 2021 — 1,000,000; December 31, 2020 — zero)

Common stock (par value — $0.01; number of shares authorized — 1,800,000,000)
(shares outstanding: December 31, 2021 — 469,072,597; December 31, 2020 —
489,305,888)

al

Treasury stock, at cost (shares: December 31, 2021 — 63,856,879; December 31, 2020
— 41,043,224)
Additional paid-in-capita
Retained deficit
Accumulated other comprehensive loss
Stockholders' equity
Noncontrolling interest in subsidiary
Total equity

Total liabilities and equity

$

e Notes to the Consolidated Financial Statements.

December 31,

2021

2020

2,000

5

(1,558)
9,824
(1,964)
(16)
8,291
1
8,292
29,683

$

—

5

(973)
9,786
(399)
(48)
8,371
(10)
8,361
25,208

93

Balances at
December 31, 2018
Stock repurchases
Shares issued for
tangible equity unit
contracts
Effeff cts of stock-based
compensation
Net loss
Dividends declared on
common stock
Adoption of new
accounting standards
Pension and OPEB
liability — change in
funded status
Other
Balances at
December 31, 2019

Effects of stock-based
compensation
Net income (loss)
Dividends declared on
common stock
Adoption of new
accounting standard
Pension and OPEB
liability — change in
funded statust
Investment by
noncontrolling
interest
Other
Balances at
December 31, 2020
Stock repurchases
Series A Preferred
Stock issued
Series B Preferred
Stock issued
Effects of stock-based
compensation

Net income (loss)
Dividends declared on
common stock
Pension and OPEB
liability — change in
funded statust
Investment by
noncontrolling
interest

VISTRA CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)

Preferred
Stock

Common
Stock

Treasury
Stock

Additional
Paid-In
Capital

Retained
Deficit

Accumulated
Other
Comprehensive
Income (Loss)

Total
Stockholders'
Equity

Noncontrolling
Interest in
Subsidiary

Total
Equity

$ — $
—

5 $ (778) $10,107 $(1,449) $
—

(641)

—

—

—

—
—

—

—

—
—

—

—
—

—

—

—
—

446

(446)

—
—

—

—

—
—

62
—

—

—

—
(2)

—

—
928

(243)

(2)

—
2

(22) $
—

7,863 $
(641)

4 $ 7,867
(641)
—

—

—
—

—

—

(8)
—

—

62
928

(243)

(2)

(8)
—

—

—
(2)

—

—

—
(1)

—

62
926

(243)

(2)

(8)
(1)

$ — $

5 $ (973) $ 9,721 $ (764) $

(30) $

7,959 $

1 $ 7,960

—
—

—

—

—

—
—

—
—

—

—

—

—
—

—
—

—

—

—

—
—

65
—

—

—

—

—
—

—
636

(266)

(4)

—

—
(1)

—
—

—

—

65
636

(266)

(4)

(18)

(18)

—
—

—
(1)

—
(12)

—

—

—

1
—

65
624

(266)

(4)

(18)

1
(1)

$ — $

5 $ (973) $ 9,786 $ (399) $

(48) $

(585)

1,000

—

—

1,000

—

—

—

—

—

—

—

—

—

—

—

—

—

—

—

(10)

(15)

60

—

—

— (1,274)

—

(290)

—

—

—

—

94

8,371 $
(585)

(10) $ 8,361
(585)

—

—

—

—

32

—

990

985

60

(1,274)

(290)

32

—

—

—

—

10

—

—

1

990

985

60

(1,264)

(290)

32

1

VISTRA CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)

Preferred
Stock

Common
Stock

Treasury
Stock

Additional
Paid-In
Capital

Retained
Deficit

Accumulated
Other
Comprehensive
Income (Loss)

Total
Stockholders'
Equity

Noncontrolling
Interest in
Subsidiary

Total
Equity

—

—

—

3

(1)

—

2

—

2

$ 2,000 $

5 $(1,558) $ 9,824 $(1,964) $

(16) $

8,291 $

1 $ 8,292

Other
Balances at
December 31, 2021

See Notes to the Consolidated Financial Statements.

95

VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.

BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Descriptiontt

of Business

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

context. See Glossary for defined terms.

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets
throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity
generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural
gas to
Vistra Energy Corp. to Vistra Corp. (Vistra) to distinguish from
end users. Effective July 2, 2020, we changed our name fromff
s (many of which use "energy"
companies that are involved in the exploring for, producing, refining, or transporting fossil fuel
gas business
in their names) and to better reflect or integrated business model, which combines a retail electricity and natural
focused on serving its customers with new and innovative products and services and an electric power generation business
leading the clean power transition through our Vistra Zero portfolio while powering the communities we serve with safe,
reliablea

ff
and affordabl

e power.

ff

t

t

Vistra has six reportablea

segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note
20 for further information concerning our reportable business segments, including an update of our reportable segments in the
third quarter of 2020.

Wintertt Stormtt

Uri

In February 2021, a severe winter storm with extremely cold temperatures

affected much of the U.S., including Texas.
This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a
significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18,
2021. Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows. The primary
drivers of the loss were the need to procure power in ERCOT at market prices at or near the price cap due to lower output from
our natural
gas deliverability issues and our coal-fueled power plants driven by coal
gas-fueled power plants driven by natural
fuel handling challenges, high fuel costs, and high retail load costs.

t

t

t

Uplift Sff

ii
ecSS uritization

Proceeds Receivable from ERCOT — As part of the 2021 regular Texas legislative sessions and in
response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed
House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were uplifted and paid to
ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri.
In October 2021, the PUCT
issued a Debt Obligation Order approving $2.1 billion financing and the methodology for allocation of proceeds to the LSEs.
In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we expect to receive approximately $544
million of proceeds from ERCOT. The Company accounted for the proceeds we will receive by analogy to the contribution
itff Entities - Revenue Recognition and the grant
model within Accounting Standards Codification (ASC) 958-605, Not-for-Prof
model within International Accounting Standard 20, Accounting for Government Grants att
nd Disclosure of Government
Assistance
, as a reduction to expenses in the statements of operations in the annual period for which the proceeds are intended
to compensate. The proceeds are expected to be received from ERCOT in the second quarter of 2022, and we concluded that
the threshold for recognizing a receivable was met in December 2021 as the amounts to be received were determinable and
ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuat
e the $2.1 billion funding
approved in the Debt Obligation Order. The associated expense reduction is reflected in fuel, purchased power costs and
delivery fees within our consolidated statements of operations as that is where the initial costs for which we are being
compensated were recorded.

ii

t

ff

ff
The final

financial impact of Winter Storm Uri continues to be subject to the outcome of potential litigation arising from
the event, or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any
supply, wholesale pricing of generation, or allocating the financial impacts of market-wide
portion of the supply chain (i.e., fuel
load shed ratablya
across all retail market participants), that is currently being considered or may be considered by any such
parties.

ff

96

COVID-II

19 Pandemic

In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and the
U.S. Government declared the COVID-19 outbreak a national emergency. The U.S. government has deemed electricity
generation, transmission and distribution as "critical infrastructure" providing essential services during this global emergency.
As a provider of critical infrastructure,
Vistra has an obligation to provide critically needed power to homes, businesses,
hospitals and other customers. Vistra remains focff used on protecting the health and well-being of its employees and the
communities in which it operates while assuring the continuity of its business operations.

t

The Company's consolidated financial statements reflect estimates and assumptim ons made by management that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and reported amounts of revenue and expenses during the reporting periods presented. The Company
considered the impact of COVID-19 on the assumptim ons and estimates used and determined that there have been no material
adverse impacm ts on the Company's results of operations for the years ended December 31, 2021 and 2020.

In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. See Note 7

for a summary of certain anticipated tax-related impacts of the CARES Act to the Company.

Recent Developments

Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which
allows us to issue green finaff
ncial instruments to fund new or existing projects that support renewabla e energy and energy
efficiency with alignment to our ESG initiatives. See below and Note 14 for more information concerning the Series B
Preferred Stock, which was issued in December 2021 under the Green Finance Framework.

ff

d StocS

Series B Preferre

k OffeO ring — On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a
private offering (Series B Offering) under our Green Finance Network. The net proceeds of the Series B Offering were
approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the proceeds
from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments. See
Note 14 forff more information concerning the Series B Preferred Stock.

Commodity-Linked Revolving Credit Facility — On February 4, 2022, Vistra Operations entered into a credit agreement
by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and
Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides forff
a $1.0 billion senior secured
commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity
provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which
al and
Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capita
general corporate purposes. See Note 11 for more information concerning the Commodity-Linked Facility.

Basis of Presentati

tt

on

The consolidated finaff

ncial statements have been prepared in accordance with U.S. GAAP and on the same basis as the
audited finaff
ncial statements included in our 2020 Form 10-K. 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 Estimtt

ates

Preparation of financial statements requires estimates and assumptim ons 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, judgments related to the potential timing of events and other estimates. In the
event estimates and/or assumptim ons prove to be different from actual amounts, adjustments are made in subsequent periods to
reflect more current information.

97

Derivative Instrumtt

ents and Mark-to-Marke

MM

t Accountingtt

t

We enter into contracts for the purchase and sale of electricity, natural

gas, coal, uranium and other commodities utilizing
futures and forwards primarily to manage commodity price and interest rate risks. If the
instruments such as options, swaps,a
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-
assets or
market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual
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 are legally characterized as settlement of derivative contracts rather than collateral. When derivative
instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and
derivative assets and liabilities are reversed. See Notes 15 and 16 for additional information regarding fair value measurement
and commodity and other derivative contractual
assets and liabilities. A commodity-related derivative contract may be
designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal
course of business.
If designated as normal, the derivative contract is accounted for under the accrual method of accounting
(not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.

t

t

Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative
instruments and hedging activities allow for hedge accounting, which provides forff
the designation of such instruments as cash
flow or fair value hedges if certain conditions are met. As of December 31, 2021 and 2020, there were no derivative positions
accounted for as cash flowff

or fair value hedges.

We report commodity hedging and trading results as revenue, fuel expense or purchased power in the consolidated
gas hedges and trading
statements of operations depending on the type of activity. Electricity hedges, financial natural
activities are primarily reported as revenue. Physical or finaff
ncial hedges for coal, diesel or uranium, along with physical natural
gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swapa
transactions are reported in the consolidated statements of operations in interest expense.

t

t

Revenue Recognitgg

iontt

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.

We record wholesale generation revenue when volumes are delivered or services are performed forff

transactions that are
not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO,
ity revenue for making installed generation and demand response
ancillary service revenue for reliabila
system reliability requirements, and certain other electricity sales contracts. See Note 5 for detailed descriptions of
available forff
revenue from contracts with customers. See Derivative Instruments and Mark-to-Markerr
revenue recognition
related to derivative contracts.

ity services, capac

t Accounting forff

a

Advertisintt

g Expense

EE

We expense advertising costs as incurred and include them within SG&A expenses. Advertising expenses totaled $48

million, $43 million and $49 million forff

the years ended December 31, 2021, 2020 and 2019, respectively.

Impairmerr

nt of Long-Li

n

ved Assets

We evaluate long-lived assets (including intangible assets with finff

ite lives) for impairment whenever indications of
are less
impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows
than the carrying value.
If there is such impairment, a loss is 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 applicablea

. See Note 21 for details of impaim rments of long-lived assets recorded in 2021 and 2020.

ff

98

Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their
details of intangible assets with

estimated useful lives based on the expected realization of economic effects. See Note 6 forff
finite lives, including discussion of fair value determinations.

n
Goodwill all nd Intantt

gibl

e All

ssets withii

e
Indefini

teii Lives

As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally
intangible assets and liabilities, then any remaining
allocated, firff st, to identifiable tangible assets and liabilities, identifiablea
excess reorganization value is allocated to goodwill. 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. See Note 6 for details of goodwill and intangible assets
with indefinite lives, including discussion of fair value determinations.

Nuclear Fuel

Nuclear fuel is capita

sheets. Amortization of nuclear fuel
purchased power costs and delivery fees in our consolidated statements of operations.

ff

alized and reported as a component of our property, plant and equipment in our consolidated balance
is calculated on the units-of-production method and is reported as a component of fuel,

Major Mainteii

nance CostsCC

Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over
the period between the majoa r 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 consolidated statements of operations.

PP
Defined Benefit Pii

ensi

on Plans and OPEB Plans

ll

Certain health care and life insurance benefits are offered to eligible employees and their dependents uponu

of such employee fromff
agreements based on either a traditional defined benefit formula or a cash balance formul
are dependent upon numerous factors, assumptions and estimates.

the retirement
the company. Pension benefits are offered to eligible employees under collective bargaining
a. Costs of pension and OPEB plans

ff

See Note 17 for additional information regarding pension and OPEB plans.

Stock-Based Compe

CC

nsationtt

Stock-based compensation is accounted forff

r
nsation. The faiff
value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model.
are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line
Forfeitures
t
basis over the requisite service period for the entire award. See Note 18 forff
additional information regarding stock-based
compensation.

in accordance with ASC 718, Compensati

on - StocS

k Compe

m

CC

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
consolidated statements of operations (i.e., the tax is billed to customers and recorded as trade accounts receivable with an
offsetting amount recorded as a liabila
ity to the taxing jurisdiction in other current liabilities in our consolidated statements of
operations).

s
Franchise and Revenue-Based TaxeTT

Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed
on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as
an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt
taxes, but we are not acting as an agent to collect the taxes from customers. We report franc
hise and revenue-based taxes in
SG&A expense in our consolidated statements of operations.

ff

99

Income Taxes

Investment tax credits are accounted forff

under the deferral method, which resulted in a reduction to the basis of our solar
and battery storage facilities of zero, zero and $2 million and a corresponding increase in the deferred tax assets in 2021, 2020
and 2019, respectively.

Deferred income taxes are provided forff
required under accounting rules. See Note 7.

temporary differences between the book and tax basis of assets and liabilities as

We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 7.

Tax Receivable All

)A
greement (TRATT

The Company accounts forff

its obligations under the TRA aRR

s a liability in our consolidated balance sheets (see Note 8).
bligation represents the discounted amount of projected payments under the TRARR . The
The carrying value of the TRA oRR
income tax rate, (b)
projected payments are based on certain assumptim ons, including but not limited to (a) the federal corporate
estimates of our taxable income in the current and future years and (c) additional states that Vistra operates in, including the
relevant tax rate and apportionment factor forff
each state. Our taxable income takes into consideration the current federal tax
code and reflects our current estimates of future results of the business.

rr

The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective
interest method. Changes in the estimated amount of this obligation resulting from changes to either the timing or amount of
TRA pRR
r value of
the obligation. These changes are included on our consolidated statements of operations under the heading of Impacts of Tax
Receivabla e Agreement.

ayments are recognized in the period of change and measured using the discount rate inherent in the initial faiff

Accountingii

for Contingen ncies

Our financial results may be affect

loss
contingencies are recorded when management determines that it is probable that a liabia lity has been incurred and that such
to interpretations of current facts and
economic loss can be reasonably estimated.
circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 13 forff
a discussion of
contingencies.

ed by judgments and estimates related to loss contingencies. Accruals forff

Such determinations are subject

ff

Cash and Cash Equivalents

ll

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 forff

specific purposes. See Note 21 forff more details

regarding restricted cash.

Property, Pyy

laPP nt and Equipment

al improvements and individual facff

Property, plant and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or
at cost for capita
ilities 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
capita

alized in accordance with accounting guidance related to capita

alization of interest cost. See Note 21.

a

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 21.

ff

100

Asset Retirement Obligll ations (ARO)O

r value is reasonably estimablea

A liabia lity 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 faiff
. 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 forff
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 forff which capita
alized
costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 21.

Regue

latorytt

Asset or Liabil

itll ytt

ii

The costs to ultimately decommission the Comanche Peak nuclear power plant are recoverablea

through the regulatory
rate making process as part of Oncor's delivery fees. As a result, the asset retirement obligation and the investments in the
decommissioning trust are accounted forff
as rate regulated operations. Changes in these accounts, including investment income
and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liabia lity
balance that is reflected in our consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred
credits.

Inventories

Inventories consist of materials and supplies, fuel stock and natural

t

gas in storage. Materials and supplies inventory is
alized when used for repairs/maintenance or capital projects,
gas in storage are reported at the lower of cost (calculated on a weighted average basis) or

valued at weighted average cost and is expensed or capita
respectively. Fuel stock and natural
t
net realizablea

value. We expect to recover the value of inventory costs in the normal course of business. See Note 21.

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 21 for discussion of these and other investments.

r

Noncontrollill ngii

t
Interes
tt

Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own. EEI is our
ility in Joppa, Illinois. This noncontrolling interest is classified as a component of

consolidated subsidiary that owns a coal facff
equity separate fromff

stockholders' equity in the consolidated balance sheets.

Treasury Stock

Treasury stock purchases are accounted forff

recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capita
See Note 14.

under the cost method whereby the entire cost of the acquired stock is
al.

Leases

At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to
control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for
consideration.

101

Right-of-use (ROU) assets represent our right to use an underlying asset forff

the lease term and lease liabia lities represent
our obligation to make lease payments arising from the lease. ROU assets and lease liabia lities are recognized at the
commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our
at the lease commencement date to determine the present
secured incremental borrowing rate based on the information availablea
value of lease payments. Operating leases are included in operating lease ROU assets, operating lease liabilities (current)
and
operating lease liabilities (noncurrent) on our consolidated balance sheet. Finance leases are included in property, plant and
equipment, other current liabilities and other noncurrent liabilities and deferred credits on our consolidated balance sheet.
Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We
apply the practical expedient permitted by ASC 842 to not separate lease and non-lease components forff
a majority of our lease
asset classes.

r

Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense

for these leases on a straight-line basis over the lease term.

We also present lessor sublease income on a net basis against the related lessee lease expense.

Adoptio

on of Accountingii

Standards Issued PriorPP

to 2021

Simplifyll

ing the Accountingtt

for Income Taxes — In December 2019, the Financial Accounting Standards Board (FASB)
ing the Accounting for Income Taxes (Topic 740). The ASU
issued Accounting Standards Update (ASU) 2019-12, Simplifyi
enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions
intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the
related to the approach forff
recognition of deferred tax liabia lities for outside basis differences. The new guidance also simplifiesff
aspects of the accounting
for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-upu
in the tax basis of goodwill. We adopted all provisions of this ASU in the first quarter of 2020, and it did not have a material
impact on our fiff nancial statements.

Changes to the Disclosure Requirements for FaiFF r Vii

alVV ue Measurement — In August 2018, the FASB issued ASU
tt orff Fair Value Measurement. The ASU removes disclosure requirements for
2018-13, Changes to the Disclosure Requirements f
(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 forff Level 3. The ASU requires new disclosures around (a) the changes in unrealized gains and losses forff
value measurements held at the end of the
the period included in other comprehensive income for recurring Level 3 fair
value
reporting period and (b) the range and weighted average of significant unobservable inputs used to develop Level 3 fair
measurements. We adopted this ASU in the first

ted disclosures are included in Note 15.

quarter of 2020, and the upda

u

ff

ff

ff

tt

Customer's Accountintt g forff

II
Implementation Costs I
ncurre

d in a C
Contract — In August 2018, the FASB issued ASU 2018-15, Customer's A'
Cloud Computing Arrangement That Is a Servi
is a service contract to determine which implementation costs to capita
stage of the implementation. The ASU also requires the customer to expense the capita
of the hosting arrangement. The customer is required to appl
capita
ff
financial statements.

ice
d in a
ce Contract. The ASU requires a customer in a cloud hosting arrangement that
alize and which costs to expense based on the project
alized implementation costs over the term
y the existing impairment and abandonment guidance on the
quarter of 2020, and it did not have a material impact on our

alized implementation costs. We adopted this ASU in the first

II
ccounting for Implementation Costs I
ncurre

Arrangement That Is a ServSS

loCC ud Computingii

SS

a

ii

tt

Finanii

cial Instrumtt

Losses. The ASU requires organizations to measure all expected credit losses forff
date based on historical experience, current conditions and reasonable and supportable foreca
first quarter of 2020, and it did not have a material impact on our financial statements.

ents—Credit Losses — In June 2016, the FASB issued ASU 2016-13, Financial Instruments — CreCC dit
financial instruments held at the reporting
sts. We adopted this ASU in the

ff

Leases — On January 1rr

, 2019, we adopted Accounting Standards Update (ASU) 2016-02, Leases (Topic

842) and all
related amendments (new lease standard) using the modified retrospective method with the cumulative-effect adjustment to the
opening balance of retained deficit for all contracts outstanding at the time of adoption. The impact of the adoption of the new
lease standard is immaterial to our net income on an ongoing basis. The primary impact of adopting the new lease standard
relates to recognition of lease liabilities and ROU assets for all leases classified as operating leases. We recognized the effect of
initially applying the new lease standard by recording ROU assets of $85 million and lease liabilities of $123 million in our
consolidated balance sheet. See Note 12 forff

the disclosures required by the new lease standard.

((

102

In March 2020, the FASB issued ASU 2020-04, Refee rence Rate Refoe rm (Topic
ence Rate Reform on Financial Reporti

of
ng. The ASU provides optional expedients and exceptions for applying GAAP to
Refere
contract modifications and hedging relationships, subject to meeting certain criteria, that refereff
nce LIBOR or another rate that is
expected to be discontinued. The amendments in the ASU are effective for all entities as of March 12, 2020 through December
31, 2022. The adoption of this guidance did not have a material impact on our financial statements.

848): Facilitation of the Effects

TT

e

ff

In March 2020, the SEC amended Rule 3-10 of Regulation S-X regarding financial disclosure requirements for registered
debt offerings involving subsidiaries as either issuers or guarantors and affiliates whose securities are pledged as collateral.
This new guidance narrows the circumstances that require separate financial statements of subsidiary issuers and guarantors and
streamlines the alternative disclosures required in lieu of those statements. This rule is effective January 4, 2021 with earlier
adoption permitted. We elected to adopt this rule in the first quarter of 2020. Accordingly, summarized financial information
has been presented only for the issuer and guarantors of the Company's registered debt securities, and the location of the
required disclosures has been moved outside the Notes to the Consolidated Financial Statements and is provided in Part II, Item
of Financial Condition and Results of Operations under Financial Condition —
7 Management's Discussion and Analysis
Guarantor Summary Financial Information.
In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470) —
Paragraphs Pursuant to SEC Release No. 33-10762, to reflect the SEC's new disclosure rules on
Amendments t
guaranteed debt securities adopted by the Company.

o SECSS

ll

tt

2.

ACQUISITIONS AND BUSINESS COMBINATION ACCOUNTING

TT
Ambit Tii

ransac

tion

On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of
gas products to
ed the purchase price of $555 million (including cash acquired
the purchase price at closing and

Vistra, completed the Ambit Transaction. Ambit is an energy retailer selling both electricity and natural
residential and small business customers in 16 states. Vistra fund
and net working capita
not assumed by Vistra.

al) using cash on hand. All of Ambit's outstanding debt was repaid fromff

ff

t

Crius TraTT nsaction

On July 15, 2019 (Crius Acquisition Date), Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra,
completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating
gas products to residential and small business
business of Crius. Crius is an energy retailer selling both electricity and natural
customers in 19 states. Vistra fund
ed the purchase price of $400 million (including $382 million for outstanding trust units)
using cash on hand.
In addition, Vistra assumed $140 million of outstanding debt and acquired $26 million of cash at the
closing of the Crius Transaction. See Note 11 for discussion of debt assumed in the Crius Transaction.

ff

t

Ambit aii nd Crius Business Combination

ii

Accountingtt

a

We believe the Ambit Transaction has (i) augmented Vistra's existing retail marketing capabi

lities with additional direct
lity and a proprietary technology platform, (ii) reduced risk and aided expansion into higher margin channels by
selling capabi
improving Vistra's match of its generation to load profile dued
to a high degree of overlap of Vistra's generation fleet with
Ambit's approximately 11 TWh of annual load, primarily in ERCOT and PJM and (iii) enhanced the integrated value
proposition through collateral and transaction efficff

iencies, particularly via Ambit's retail electric portfolio.

a

We believe the Crius Transaction has (i) reduced risk and aided expansion into higher margin channels by improving
to a high degree of overlap of Vistra's generation fleet with Crius'
shed a platform for growth by leveraging Vistra's existing retail
lities and Crius' experienced team and (iii) enhanced the integrated value proposition through collateral and

Vistra's match of its generation to load profile dued
approximately 10 TWh of annual electricity load, (ii) establia
marketing capabi
transaction efficff

iencies, particularly via Crius' retail electric portfolio.

a

103

Each of the Ambit Transaction and Crius Transaction, respectively, was accounted for in accordance with ASC 805,
Business Combinations (ASC 805), with identifiablea
assets acquired and liabilities assumed recorded at their estimated fair
values on the Ambit Acquisition Date and Crius Acquisition Date, respectively. The combined results of operations are
reported in our consolidated financial statements beginning as of the respective Ambit Acquisition Date and Crius Acquisition
Date. A summary of the techniques used to estimate the fair value of the identifiable assets and liabilities, as well as their
classification within the fair value hierarchy (see Note 15), is listed below:

• Working capia tal was valued using availablea market information (Level 2).
•
•

Acquired derivatives were valued using the methods described in Note 15 (Level 2 or Level 3).
Acquired retail customer relationship was valued based on discounted cash flow analysis of acquired customers and
estimated attrition rates (Level 3).
Crius' long-term debt was valued using a market approach (Level 2).

•

The following tablea

summarizes the allocation of the purchase price to the fair value amounts recognized for the assets
acquired and liabilities assumed related to the Ambit Transaction and Crius Transaction, respectively, as of the Ambit
Acquisition Date and Crius Acquisition Date, respectively. The Ambit Transaction purchase price was $555 million (including
cash acquired and net working capita
al) and the Crius Transaction purchase price was $400 million. The final purchase price
allocations were completed in the second quarter of 2020 for the Crius Transaction and the third quarter of 2020 for the Ambit
Transaction.

Ambit Transaction and Crius Transactions Final Purchase Price Allocations

Cash and cash equivalents
Net working capia tal
Accumulated deferred income taxes
Identifiable intangible assets
Goodwill
Commodity and other derivative contractual assets
Other noncurrent assets
Total assets acquired
Identifiable intangible liabila
Long-term debt, including amounts due currently
Commodity and other derivative contractual
Accumulated deferred income taxes
Other noncurrent liabilities and deferred credits

ities

t

liabilities

Total liabilities assumed
Identifiable net assets acquired

Ambit Transaction

Crius Transaction

Final
Purchase Price
Allocation

Measurement
Period Adjustmen
d
recorded

ts

Final
Purchase Price
Allocation

Measurement
Period Adjustmen
d
recorded

ts

$

$

49
32
—
218
258
23
13
593
—
—
28
—
10
38
555

$

$

— $
3
—
(45)
44
—
—
2
—
—
—
—
2
2
— $

26
(9)
—
317
243
18
17
612
2
140
40
14
16
212
400

$

$

—
(42)
(36)
23
38
—
(3)
(20)
(34)
—
—
14
—
(20)
—

quisition costs incurred in the Ambit Transaction and Crius Transaction totaled $1 million and $2 million, respectively.
For the Ambit Acquisition Date through December 31, 2019, our consolidated statements of operations include revenues and
net income acquired in the Ambit Transaction totaling $193 million and $2 million, respectively. For the Crius Acquisition
Date through December 31, 2019, our consolidated statements of operations include revenues and net income acquired in the
Crius Transaction totaling $453 million and zero, respectively. The net income acquired in the Ambit Transaction and Crius
Transaction include intangible amortization and transition related expenses.

104

Ambit and Crius Transaction Unaudited Pro Forma FinFF ancial Information — The following unaudited consolidated pro
the year ended December 31, 2019 assumes that the Ambit and Crius Transactions occurred on
forma financial inforff mation forff
January 1, 2019 (i.e., represents our results forff
the year ended December 31, 2019 plus the results for either Ambit Transaction
or Crius Transaction for the period not owned by us, respectively). The unaudited consolidated pro forma financial inforff mation
is provided forff
informational purposes only and is not necessarily indicative of the results of operations that would have
occurred had the Ambit Transaction and Crius Transaction been completed on January 1, 2019, nor is the unaudited
consolidated pro forma financial information indicative of future results of operations, which may differ materially fromff
the
consolidated pro forma financial information presented here.

Revenues
Net income (a)
Net income attributable to Vistra
Net income attributable to Vistra per weighted average share of common stock
outstanding — basic
Net income attributable to Vistra per weighted average share of common stock
outstanding — diluted

Ambit Transaction

Crius Transaction

Year Ended
December 31, 2019
12,931
949
951

1.92

1.90

$
$
$

$

$

Year Ended
December 31, 2019
12,373
876
878

1.78

1.76

$
$
$

$

$

__________
(a) Decrease in pro forma net income compared to consolidated net income is driven by unrealized losses on hedging

activities of Crius and amortization of intangible assets.

The consolidated unaudited pro forma financial inforff mation presented above includes adjustments for incremental
depreciation and amortization as a result of the fair value determination of the net assets acquired and the related impacts on tax
expense.

105

3.

DEVELOPMENT OF GENERATRR ION FACILITIES

ee
Texas

Segment Solarll Generation and Energy Storage Projects

We have announced our planned development of up to 768 MW of solar photovoltaic power generation facilities and 260
MW of battery ESS in Texas. The first 158 MW of solar generation came online in January and February 2022. Estimated
commercial operation dates for the remaining facilities range from the second quarter of 2022 to fourth quarter of 2023. As of
ately $286 million in construction-work-in-process for these Texas segment
December 31, 2021, we had accumulated approxim
solar generation and battery ESS projects.

a

East SegSS megg

nt Solarll GenerGG

SS
ation and Energy Sgg

torage

Projects

In September 2021, we announced the planned development of up to 300 MW of solar photovoltaic power generation
facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois
Senate Bill 2408, the Energy Transition Act. Estimated commercial operation dates for these facilities range from 2023 to
2025.

West Segment Energy Storage Projectstt

Oakland — In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy
capac
. In April 2020,
ity fromff
the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California
a
the project received necessary approvals from EBCE and from Pacific Gas and Electric Company (PG&E). The contract was
ity of the planned development to a 36.25 MW battery ESS. In April 2020, the concurrent Local
amended to increase the capac
Area Reliabila
ity as part of the Oakland Clean Energy Initiative was signed,
l. PG&E did not receive CPUC approval as of April 15,
but required California Public Utilities Commission (CPUC) approva
2021. On April 16, 2021, Vistra terminated the LARS agreement with PG&E. We are continuing development of the Oakland
battery ESS project while seeking another contractual arrangement that will allow the investment to move forward.

ity Service (LARS) agreement to ensure grid reliabila

a

a

ff

Moss Landing — In June 2018, we announced that, subject to approva

l by the CPUC, we would enter into a 20-year
resource adequacy contract with PG&E to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California
ication with the CPUC in June 2018 and the CPUC approved the resource
(Moss Landing Phase I). PG&E filed its appl
adequacy contract in November 2018. Under the contract, PG&E will pay us a fixeff
d monthly resource adequacy payment,
while we will receive the energy revenues and incur the costs from dispatching and charging the ESS. Moss Landing Phase I
commenced commercial operations in May 2021.

a

a

ff

In May 2020, we announced that, subject to approva

l by the CPUC, we would enter into a 10-year resource adequacy
contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase
II). PG&E filed its appl
ication with the CPUC in May 2020 and the CPUC approved the resource adequacy contract in August
2020. Moss Landing Phase II commenced commercial operations in July 2021.

a

a

The total development costs for Moss Landing Phases I and II totaled approximately $600 million.

In January 2022, we announced that, subject to approva

l by the CPUC, we would enter into a 15-year resource adequacy
contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase
III). PG&E filed its appl
ication with the CPUC in January 2022, and CPUC approval is expected in the second quarter of 2022.
Moss Landing Phase III is expected to enter commercial operations in the summer of 2023.

a

a

Moss Landing Outages — In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the
battery ESS. A review found that only a small, single-digit percentage of batteries at the facility were impacted and that the
ystem. The facility will be offline as we perform the work necessary
root cause originated in systems separate fromff
to return the facff

the battery srr
ility to service. Moss Landing Phase II was not affected by this incident.

In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery Err

SS. An
investigation is underway to determine the root cause of the incident. The facility will be offline as we perform the work
necessary to return the facility to service. Moss Landing Phase I was not affected by the incident, but the facility will remain
offline during the assessment stage of the Moss Landing Phase II incident.

We do not expect these incidents to have a material impact on our results of operations.

106

4.

RETIREMENT OF GENERATION FACILITIES

Sunset SegSS megg

nt

Operational results forff

plants with defined retirement dates identified below are included in our Sunset segment beginning

in the quarter when a retirement plan is announced.

Name

Location

Baldwin
Coleto Creek
Edwards
Joppa
Joppa
Kincaid
Miami Fort
Newton
Zimmer
Total

Baldwin, IL
Goliad, TX
Bartonville, IL
Joppa, IL
Joppa, IL
Kincaid, IL
North Bend, OH
Newton, IL
Moscow, OH

ISO/RTO
MISO
ERCOT
MISO
MISO
MISO
PJM
PJM
MISO/PJM
PJM

Fuel Type
Coal
Coal
Coal
Coal
Natural Gas
Coal
Coal
Coal
Coal

Net Generation
Capacity (MW)

1,185
650
585
802
221
1,108
1,020
615
1,300
7,486

Expected Retirement Date (a)
By the end of 2025
By the end of 2027
By the end of 2022
By September 1, 2022
By September 1, 2022
By the end of 2027
By the end of 2027
By the end of 2027
By May 31, 2022

____________
(a) Generation facilities may retire earlier than expected dates if economic or other conditions dictate.

In September 2019, we announced the settlement of a lawsuit alleging violations of opacity and particulate matter limits at
our Edwards facility in Bartonville, Illinois. As part of the settlement, which was approved by the U.S. District Court for the
Central District of Illinois in November 2019, we will retire the Edwards facility by the end of 2022 (see Note 13).

In September 2020 and December 2020, we announced our intention to retire all of our remaining coal generation
facilities in Illinois and Ohio, one coal generation facility in Texas and one natural
lity in Illinois no later than year-end
2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rulrr e and
ELG rulerr
(see Note 13), and in furtherance of our efforts to significantly reduce our carbon footprint. Expected plant retirement
expenses of $43 million, driven by severance cost, were accrued in the year ended December 31, 2020 in operating costs of our
Sunset segment.

ff
gas faci

t

In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022 in order to settle a
complaint fileff d with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018 (see Note 13). We had previously
announced that Joppa would retire no later than the end of 2027. In July 2021, we announced we would retire the Zimmer coal
generation facility by May 31, 2022 due to the inability to secure capac
ity
auction held in May 2021. We had previously announced that Zimmer would retire no later than the end of 2027.

ity revenues for the plant in the latest PJM capac

a

a

See Note 21 for discussion of impaim rments recorded in connection with these announcements.

ll
Asset Closure

Segment

Operational results forff

the Illinois plants retired in 2019 identified below are included in the Asset Closure segment. The
Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines, including those retired
prior to 2019.

Name

Location

ISO/RTO

Fuel Type

Net Generation
Capacity (MW)

Coffeen

Coffeen, IL

Duck Creek

Canton, IL

Havana

Hennepin

Total

Havana, IL

Hennepin, IL

MISO

MISO

MISO

MISO

Coal

Coal

Coal

Coal

915

425

434

294

2,068

Dates Units Retired

November 1, 2019

December 15, 2019

November 1, 2019

November 1, 2019

107

a

ity of 2,068 MW. We retired these units dued

In August 2019, we announced the planned retirement of four power plants in Illinois with a total installed nameplate
to changes in the Illinois Multi-Pollutant Standard rule (MPS
generation capac
rule) that require us to retire approximately 2,000 MW of generation capac
ity. In light of the provisions of the Federal Power
Act and the FERC regulations thereunder, the affected subsidiaries of Vistra identified the retired units by analyzing the
economics of each of our Illinois plants and designating the least economic units forff
retirement. Expected plant retirement
expenses of $47 million, driven by severance costs, were accrued in the year ended December 31, 2019 and were included
primarily in operating costs of our Asset Closure segment in our consolidated statements of operations.
In August 2019, we
remeasured our pension and OPEB plans resulting in an increase to the benefit obligation liability of $21 million, pretax other
comprehensive loss of $18 million and curtailment expense of $3 million recognized as other deductions in our consolidated
statements of operations.

a

5.

REVENUE

The following tablea

s disaggregate our revenue by majoa r source:

Revenue from contracts with
customers:

Retail energy charge in ERCOT
Retail energy charge in Northeast/
Midwest
Wholesale generation revenue from
ISO/RTO
Capac
a
Revenue from other wholesale
contracts

ity revenue from ISO/RTO (a)

Total revenue from contracts with
customers

Other revenues:

Intangible amortization
Hedging and other revenues (b)
Affiliate sales (c)

Total other revenues
Total revenues

Retail

Texas

East

West

Sunset

Asset
Closure

Eliminations Consolidated

Year Ended December 31, 2021

$ 5,733

$ — $ — $ — $ — $ — $

— $

5,733

2,255

—

—

— 3,808
—
—

786
(22)

— 2,302

602

—

229
1

104

—

1,525
184

193

7,988

6,110

1,366

334

1,902

—

—
—

—

—

—

—
—

—

—

(2)
(115)

—
(4,355)
— 1,035
(3,320)
$ 2,790

(117)
$ 7,871

74
123
1,024
1,221
$ 2,587

—
35
5
40
374

(12)
(1,371)
220
(1,163)
739
$

—
—
—
—
$ — $

—
—
(2,284)
(2,284)
(2,284) $

$

2,255

6,348
163

3,201

17,700

60
(5,683)
—
(5,623)
12,077

____________
(a) Represents net capac

a

t
ity s

old (purchased) in each ISO/RTO. The East segment includes $470 million of capac
ity sold. The Sunset segment includes $4 million of capac

purchased offset by $448 million of capac
by $188 million of capaa
Includes $1.191 billion of unrealized net losses from mark-to-market valuations of commodity positions. See Note 20
forff

ity
ity purchased offset

unrealized net gains (losses) by segment.

city sold.

a

a

a

(b)

(c) Texas and East segments include $1.028 billion and $529 million, respectively, of affiliated unrealized net losses from

mark-to-market valuations of commodity positions with the Retail segment.

108

Retail

Texas

East

West

Sunset

Asset
Closure

Eliminations Consolidated

Year Ended December 31, 2020

$ 5,813

$ — $ — $ — $ — $ — $

— $

5,813

Revenue from contracts with
customers:

Retail energy charge in ERCOT
Retail energy charge in Northeast/
Midwest
Wholesale generation revenue from
ISO/RTO
a
Capac
Revenue from other wholesale
contracts

ity revenue from ISO/RTO (a)

2,406

—
—

—

—

475
—

226

701

—

310
(52)

668

926

Total revenue from contracts with
customers

8,219

Other revenues:

Intangible amortization
Hedging and other revenues (b)
Affiliate sales

Total other revenues
Total revenues

—
(5)
416
56
— 2,999
51
3,415
$ 4,116
$ 8,270

2
(108)
1,595
1,489
$ 2,415

$

—

124
—

54

178

—
101
3
104
282

—

473
164

187

824

(21)
151
298
428
$ 1,252

$

—

1
—

1

2

—
1
—
1
3

—

—
—

—

—

—
—
(4,895)
(4,895)
(4,895) $

$

2,406

1,383
112

1,136

10,850

(24)
617
—
593
11,443

____________
(a) Represents net capac

a

t
ity s

old (purchased) in each ISO/RTO. The East segment includes $542 million of capac
ity sold. The Sunset segment includes $3 million of capac

purchased offset by $490 million of capac
by $167 million of capaa
Includes $164 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 20 forff
unrealized net gains (losses) by segment.

ity
ity purchased offset

city sold.

a

a

a

(b)

Revenue from contracts with
customers:

Retail energy charge in ERCOT
Retail energy charge in Northeast/
Midwest
Wholesale generation revenue from
ISO/RTO
Capac
a
Revenue from other wholesale
contracts

ity revenue from ISO/RTO (a)

Total revenue from contracts with
customers

Other revenues:

Intangible amortization
Hedging and other revenues (b)
Affiliate sales

Total other revenues
Total revenues

Retail

Texas

East

West

Sunset

Asset
Closure

Eliminations Consolidated

Year Ended December 31, 2019

$ 4,983

$ — $ — $ — $ — $ — $

— $

4,983

1,818

—

— 1,477
—
—

—

264

—

629
170

702

—

193
—

9

—

751
197

147

—

194
11

2

6,801

1,741

1,501

202

1,095

207

—

—
—

—

—

—
(15)
86
(250)
— 2,345
2,095
71
$ 3,836
$ 6,872

(4)
37
1,256
1,289
$ 2,790

$

4
132
—
136
338

(17)
247
277
507
$ 1,602

$

—
42
92
134
341

$

—
—
(3,970)
(3,970)
(3,970) $

1,818

3,244
378

1,124

11,547

(32)
294
—
262
11,809

____________
(a) Represents net capac

a

t
ity s

purchased offset by $613 million of capac
by $198 million of capaa

city sold.

old (purchased) in each ISO/RTO. The East segment includes $443 million of capac
ity sold. The Sunset segment includes $1 million of capac

ity
ity purchased offset

a

a

a

109

(b)

Includes $682 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 20 for
unrealized net gains (losses) by segment.

EE
Retail Eii

nergy

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 fromff
revenue. Payment terms vary from 15 to 60 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 adjuste

d when actual usage is known and billed.

d

As contracts for retail electricity can be forff multi-year periods, the Company has performff

ance 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.

ll
Wholesale

s
Generation Revenue from ISOs/RTO//

Revenue is recognized when volumes are delivered to the ISO/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 operates as a market
participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with
each ISO/RTO indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted forff
as a single performanc
e obligation. When electricity is sold to and purchased from the same ISO/RTO in the same period, the
excess of the amount sold over the amount purchased is reflected in wholesale generation revenues.

ff

Capacityii Revenue From ISO/RTO//

a

We offer generation capac
city ensures installed generation and demand response is available to satisfy system integrity and reliabila
city revenues are recognized when the performanc

ity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers.
ity requirements.
Capaa
Capaa
e obligation is satisfied ratably over time as our power generation
facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if
the facility is not available during
ity is
sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is
reflected in capacity revenue.

ity period. The penalties are recorded as a reduction to revenue. When capac

a
the capac

d

a

ff

Revenue from Other

tt Wholesale

ll

tt
Contracts

Other wholesale contracts include other revenue activity with the ISO/RTO, 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 performff
ed. Revenue is recognized over time using the output method based on
icable measurements, and cash settles shortly after invoicing. Vistra operates as a market
kilowatt hours delivered or other appl
participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with
each ISO/RTO indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted forff
as a
single performance obligation.

a

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, is reported in the tabla e aboa ve as hedging and other revenues. We have
classifiedff

ates that are eliminated in consolidation as other revenues in the tablea

all sales to affili

above.

ff

110

Contratt

ct and Other

tt

Customer Acquisitiii on Costs

We defer costs to acquire retail contracts and amortize these costs over the expected life off

f 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 both December 31, 2021 and 2020 was $80 million. The
amortization related to these costs during the year ended December 31, 2021, 2020 and 2019 totaled $75 million, $46 million
and $21 million respectively, recorded as SG&A expenses, and $6 million, $7 million and $9 million, respectively, recorded as
a reductd

ion to operating revenues in the consolidated statements of operations.

Practictt al Expedi

xx

ents

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 have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for
which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar
customer contracts with similar performance obligations. Sales taxes are not included in revenue.

Performance Obligati

i

ons

As of December 31, 2021, we have futuff
re performff
a
ity auction volumes awarded through capac

ance obligations that are unsatisfied, or partially unsatisfied, relating to
capac
ity auctions held by the ISO/RTO or contracts with customers. Therefore, an
a
obligation exists as of the date of the results of the respective ISO/RTO capacity auction or the contract execution date. These
obligations total $652 million, $310 million, $212 million, $99 million and $45 million that will be recognized in the years
ity revenues are
ending December 31, 2022, 2023, 2024, 2025 and 2026, respectively, and $439 million thereafter. Capac
recognized as capacity is made available to the related ISOs/RTOs or counterparties.

a

Accounts Receivablell

The following tablea

presents trade accounts receivable (net of allowance forff

uncollectible accounts) relating to both

contracts with customers and other activities:

Trade accounts receivable fromff
Other trade accounts receivablea — net
Total trade accounts receivablea — net

contracts with customers — net

6. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwillll

The following tabla e provides information regarding our goodwill balance.

Balance at December 31, 2018
Measurement period adjustments recorded in connection with the Merger
Goodwill recorded in connection with the Crius Transaction
Goodwill recorded in connection with the Ambit Transaction
Balance at December 31, 2019
Measurement period adjustments recorded in connection with the Crius Transaction
Measurement period adjustments recorded in connection with the Ambit Transaction
Balance at December 31, 2021 and 2020

December 31,

2021

2020

$

$

1,087
310
1,397

$

$

1,169
110
1,279

$

$

2,068
14
257
214
2,553
(14)
44
2,583

As of December 31, 2021, the carrying value of goodwill totaled $2.583 billion and consisted of the following:

•

•

•

•

$1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated
tax
entirely to our Retail reporting unit. Of the goodwill recorded at Emergence, $1.686 billion is deductible forff
purposes over 15 years on a straight-line basis.
$175 million arose in connection with the Merger, of which $122 million was allocated to our Texas Generation
reporting unit and $53 million was allocated to our Retail reporting unit. None of the goodwill related to the Merger
is deductible for tax purposes.
$243 million of goodwill arose in connection with the Crius Transaction and was allocated entirely to our Retail
reporting unit. None of the goodwill related to the Crius Transaction is deductible forff
$258 million of goodwill arose in connection with the Ambit Transaction and was allocated entirely to our Retail
tax purposes over 15 years on a
reporting unit. The goodwill related to the Ambit Transaction is deductible forff
straight-line basis.

tax purposes.

Goodwill and intangible assets with indefinite useful lives are required to be evaluated forff

impairment at least annually or
whenever events or changes in circumstances indicate an impairment may exist. 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 Retail and Texas Generation reporting units exceeded their carrying value at October 1,
2021. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors,
customer attrition and changes in reporting unit book value.

ii
Identifi
tt able

Intangible

tt

Assets and Liabiliii tiii es

Identifiable intangible assets are comprised of the folff

lowing:

Identifiable Intangible Asset
Retail customer relationship
Software and other technology-related assets
Retail and wholesale contracts
Contractual service agreements (a)
Other identifiablea

intangible assets (b)

Total identifiablea
amortization

intangible assets subject to

Retail trade names (not subjb ect to amortization) (c)
Mineral interests (not currently subject to
amortization)

Total identifiablea

intangible assets

December 31, 2021

December 31, 2020

$

Gross
Carrying
Amount
2,083
421
248
23
95

$

Accumulated
Amortization
1,631
$
206
206
2
20

$

2,870

$

2,065

Net

452
215
42
21
75

805
1,341

$

Gross
Carrying
Amount
2,082
414
272
51
96

$

Accumulated
Amortization
1,434
$
186
204
1
19

$

2,915

$

1,844

Net

648
228
68
50
77

1,071
1,374

—
$ 2,146

1
$ 2,446

____________
(a) As of December 31, 2021 and 2020, amounts related to contractual service agreements that have become liabilities due to
amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and
accumulated amortization.

(b) Includes mining development costs and environmental allowances (emissions allowances and renewablea

energy

certificates).

(c) During the year ended December 31, 2021, we recorded a $33 million impairment to a retail trade name intangible asset.

Identifiable intangible liabila

ities are comprised of the following:

Identifiable Intangible Liability
Contractual service agreements
Purchase and sale of power and capaa
Fuel and transportation purchase contracts
intangible liabilities

Total identifiablea

city

Year Ended December 31,

2021

2020

$

$

125
8
14
147

$

$

129
87
73
289

112

Expense related to finite-lived identifiablea

intangible assets and liabilities (including the classification in the consolidated

statements of operations) consisted of:

Identifiable Intangible
Assets and Liabilities
Retail customer
relationship
Software and other
technology-related
assets
Retail and wholesale
contracts/purcha
/
and sale/fuel and
transportation
contracts
Other identifiablea
intangible assets

se

Consolidated Statements of
Operations

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

Total intangible asset expense (a)

Remaining usefuff l
lives of identifiable
intangible assets at
December 31,
2021 (weighted
average in years)

3

4

3

5

Year Ended December 31,

2021

2020

2019

$

197

$

283

$

275

74

(56)

73

17

279

494

$

223

596

$

$

61

23

148

507

____________
(a) Amounts recorded in depreciation and amortization totaled $275 million, $360 million and $340 million for the years
ended December 31, 2021, 2020 and 2019 respectively. Amounts exclude contractual services agreements. Amounts
include all expenses associated with environmental allowances including expenses accrued to comply with emissions
allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery
fees on our consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is
generated and renewable energy certificate obligations are accruedr

as retail electricity delivery occurs.

The following is a description of the separately identifiable intangible assets. In connection with fresh start reporting, the
Merger, the Crius Transaction and the Ambit Transaction, the intangible assets were adjusted based on their estimated fair value
as of the Effective Date, the Merger Date, the Crius Acquisition Date and the Ambit Acquisition Date, respectively, based on
observable prices or estimates of fair value using valuation models.

•

•

•

l

Retail customer relati
onship — 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 assets represent the fair
value of our retail brands, including
the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield Energy, Dynegy Energy Services,
TriEagle Energy, Public Power and U.S. Gas & Electric, and were determined to be indefinite-lived assets not subject
to amortization. These intangible assets are evaluated forff
impairment at least annually in accordance with accounting
guidance related to goodwill and other indefinite-lived intangible assets. Significant assumptim ons included within the
development of the fair value estimates include estimated gross margins for future periods and implied royalty rates.
On the most recent testing date, we recorded an impairment charge for $33 million related to an immaterial trade
name. For all other trade names, we determined it was more likely than not that the fair value of the retail trade name
intangible assets exceeded their carrying values at October 1, 2021.

ff

t

e and sale contracts

— These intangible assets represent the value of various
ss
Retail and wholesale contracts
/purchas
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, the Merger Date, the Crius Acquisition Date or
the Ambit Acquisition 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.

tt

113

•

or unfavorablea

contract obligations with respect

r value of
Contractual service agreementstt — Our acquired contractual service agreements represent the estimated faiff
favorablea
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
ty of the plant maintenance services relate to capital improvements
agreements over the contract terms. The majori
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.

a

Estimatedtt Amortization

ii

i
of Identifi
tt able

Intangible

tt

Assets and Liabiliii tiii es

As of December 31, 2021, the estimated aggregate amortization expense of identifiablea

intangible assets and liabilities for

each of the next fivff e fisff cal years is as shown below.

Year
2022
2023
2024
2025
2026

7.

INCOME TAXES

Estimated Amortization Expense
202
$
148
$
99
$
73
$
49
$

Vistra filff es a U.S. federal income tax returnt

that includes the results of its consolidated subsidiaries. Vistra is the
corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and
published guidance of the IRS, corporations that are members of a consolidated group have joint and several liabia lity for the
taxes of such group.

Income Tax Expense

xx

(Benefit)ii

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

ff

s:

Current:

U.S. Federal
State

Total current

Deferred:

U.S. Federal
State

Total deferred
Total

Year Ended December 31,

2021

2020

2019

$

$

$

1
16
17

(336)
(139)
(475)
(458) $

(5) $
41
36

171
59
230
266

$

(1)
10
9

260
21
281
290

114

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

Income (loss) before income taxes
U.S. federal statutory rate
Income taxes at the U.S. federal statutory rate
Nondeductible TRA accretion
State tax, net of federal benefit
Federal and State returnt
Nondeductible compensation
Nondeductible transaction costs
Equity awards
Valuation allowance on state NOLs
Lignite depletion
Texas gross margin amended returnt
Other

to provision adjust

d ment

Income tax expense (benefit)
Effective tax rate

Defere

red IncII ome Tax Balances

Year Ended December 31,

2021
(1,722)

$

2020

2019

$

890

$

1,216

21 %

(362)
(8)
(2)
(2)
4
—
1
(94)
(3)
—
8
(458)
26.6 %

$

21 %

187
(7)
32
13
—
—
—
41
(3)
—
3
266
29.9 %

$

21 %
255
5
48
(17)
3
2
(4)
13
(6)
(3)
(6)
290
23.8 %

$

Deferred income taxes provided forff

temporary differences based on tax laws in effect at December 31, 2021 and 2020 are

as follows:

Noncurrent Deferred Income Tax Assets

Tax credit carryforwards
Loss carryforwards
Identifiable intangible assets
Long-term debt
Employee benefit obligations
Commodity contracts and interest rate swapsa
Other

Total deferred tax assets

Noncurrent Deferred Income Tax Liabilities

Property, plant and equipment
ities
Total deferred tax liabila

Valuation allowance

Net Deferff red Income Tax Asset

December 31,

2021

2020

76
1,193
346
15
121
238
148
2,137

767
767
68
1,302

$

$

$

75
953
293
19
129
96
47
1,612

632
632
143
837

$

$

$

a

As of December 31, 2021, we had total deferred tax assets of approxi

mately $1.302 billion that were substantially
comprised of book and tax basis differences related to our generation and mining property, plant and equipment, as well as
l and state net operating loss (NOL) carryforwards. Our deferred tax assets were significantly impacted by the impacts of
ff
federa
Winter Storm Uri as well as the Merger. For the year ended December 31, 2021, we recognized a tax benefit of $74 million on
the release of state valuation allowances largely related to Illinois.
Illinois enacted legislation in 2021 extending the
carryforward period of net operating losses and we forecast to utilize all losses before expiration. For the year ended December
31, 2020, we recognized a partial valuation allowance of $32 million on the net operating loss carryforwards related largely to
Illinois and New York due to forecasted expiration. As of December 31, 2021, we assessed the need forff
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 futuret

income, and thus no valuation allowance was required.

taxablea

115

As of December 31, 2021, we had $4.5 billion pre-tax net operating loss (NOL) carryforwards for federal income tax
purposes that will begin to expire in 2032. As of December 31, 2021, we had no remaining AMT credits refundable through
.
the TCJA availablea

The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax

liability of $9 million at December 31, 2021 and a net deferred tax asset of $5 million at December 31, 2020.

Coronavirus Aid, Relief aff nd Economic SecSS urityii Act (CARES AEE

tt
ct) at nd Final Sectiott n 163(j) Regulat
ions

e

the ability to accelerate timing of refundablea

In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. The
CARES Act provides numerous relief provisions for corporate taxpayers, including modification of the utilization limitations
expansion of the deduction for business interest expense under IRC Section 163(j) (Section
on net operating losses, favorablea
163(j)),
AMT credits and the temporary suspension of certain payment
requirements forff
the employer portion of social security taxes. Additionally, the final Section 163(j) regulations were issued in
July 2020 and provided a critical correction to the proposed regulations with respect to the computation of adjusted taxable
income. In 2021, Vistra is benefiting from the final 163(j) regulations and able to utilize its remaining 163(j) carryforward of
$12 million. Certain provisions in the final 163(j) regulations begin to sunset in 2022, for which Vistra will continue its
legislative monitoring and advocacy efforts to amend consistent with the intent of the law, including the permanent addback of
d taxable income. Vistra is also utilizing the CARES Act payroll deferral mechanism to
depreciation and amortization to adjuste
mately half of the previously
defer the payment of approximately $22 million from 2020 to 2021 and 2022. We paid approxi
deferred taxes in December 2021.

d

a

i
Liabil

tt
itll y f

orff Uncertain Tii

axTT

tt
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 benefitff based on a "more-likely-than-not" standard with respect to
the ultimate outcome, regardless of whether this assessment is favorablea

.
or unfavorablea

We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were
immaterial for the years ended December 31, 2021, 2020 and 2019. The following tablea
summarizes the changes to the
uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance
sheets forff

the years ended December 31, 2021, 2020 and 2019.

ions based on tax positions related to prior years

Balance at beginning of period, excluding interest and penalties
Additions based on tax positions related to prior years
Reductd
Additions based on tax positions related to the current year
Settlements with taxing authorities
Balance at end of period, excluding interest and penalties

Year Ended December 31,

2021

2020

2019

39
1
—
—
(2)
38

$

$

126
3
(90)
—
—
39

$

$

39
3
—
87
(3)
126

$

$

Vistra and its subsidiaries filff e income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject
In February 2021, Vistra was notified that the IRS had opened a
tax years 2018 and 2019 and an employment tax audit for tax year 2018. Crius is currently under

to examinations by the IRS and other taxing authorities.
federal income tax audit forff
audit by the IRS forff

the tax years 2015 and 2016. Uncertain tax positions totaled $38 million at December 31, 2021.

Tax Matters

tt

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 is generally required to reimburse EFH Corp. with
respect to any taxes paid by EFH Corp. that are attributablea
to us and (b) EFH Corp. is generally required to reimburse us with
respect to any taxes paid by us that are attributablea

to EFH Corp.

116

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 fromff
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
the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d)
obtained fromff
we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptablea
to EFH Corp.
that the action will not affect the intended tax treatment of the Spin-Off.

8.

TAX RECEIVABLE AGREEMENT OBLIGATION

ff

ien creditors of TCEH. The TRA gRR

On the Effective Date, Vistra entered into a tax receivable agreement (the TRARR ) with a transfer agent on behalf of certain
former first-l
ights of 85% of
the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of
(a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets
resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition of two
CCGT natural
gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be paid
by us as a result of payments under the TRA,RR plus interest accruing

from the due date of the applicable tax return.

the payment by us to holders of TRA RRR

enerally provides forff

r

t

Pursuant to the TRARR , we issued the TRA RRR

receive such TRA RRR
fully described in the Registration Rights Agreement (see Note 19).

ights under the Plan of Reorganization. Such TRA RRR

ights for the benefit of the first-lien secured creditors of TCEH entitled to
ights are entitled to certain registration rights more

The following tablea

summarizes the changes to the TRA oRR

bligation, reported as other current liabilities and Tax

Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2021, 2020 and 2019.

bligation at the beginning of the period

TRA oRR
Accretion expense
Changes in tax assumptions impacting timing of payments (a)

Impacts of Tax Receivable Agreement

Payments
TRA oRR

bligation at the end of the period

Less amounts dued

currently

Noncurrent TRA oRR

bligation at the end of the period

Year Ended December 31,

2021

2020

2019

$

$

450
62
(115)

(53)
(2)
395
(1)
394

$

$

455
64
(69)

(5)
—
450
(3)
447

$

$

420
59
(22)

37
(2)
455
—
455

ff

____________
(a) During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA oRR

bligation totaling
asted taxable income, including the financial impacts of Winter Storm Uri,
$115 million as a result of adjustments to forec
planned additional renewable development projects.
and anticipated tax benefits available under current tax laws forff
bligation totaling
During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA oRR
asted taxable income, including the impacts of the CARES
approximately $69 million as a result of adjustments to forec
Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j)
renewable development projects. During the year ended December 31,
regulations and the anticipated tax benefits fromff
2019, we recorded an decrease to the carrying value of the TRA oRR
bligation totaling $22 million as a result of adjustments
to the timing of forecasted taxable income and state apportionment due to the expansion of Vistra's state income tax
profile, including the Dynegy, Crius and Ambit acquisitions.

ff

117

rr

As of December 31, 2021, the estimated carrying value of the TRA oRR

bligation totaled $395 million, which represents the
discounted amount of projected payments under the TRARR . The projected payments are based on certain assumptions, including
but not limited to (a) the federal corporate
income tax rate of 21%, (b) estimates of our taxable income in the current and future
each
years and (c) additional states that Vistra now operates in, including the relevant tax rate and apport
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. The estimates of future business results include assumptions related to
renewable development projects that Vistra is planning to execute that generate significant tax benefits. These benefits have a
bligation payments. These assumptim ons are subject to change, and those changes could
material impact on the timing of TRA oRR
have a material impact on the carrying value of the TRA oRR
bligation. As of December 31, 2021, the aggregate amount of
undiscounted federal and state payments under the TRA iRR s estimated to be approximately $1.4 billion, with more than half of
such amount expected to be paid during
the next 15 years, and the final payment expected to be made around the year 2056 (if
the TRA iRR s not terminated earlier pursuant to its terms).

ionment factor forff

d

a

ff

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 TRARR
r value of the
payments are recognized in the period of change and measured using the discount rate inherent in the initial faiff
obligation.

9.

EARNINGS PER SHARE

Basic earnings per share availablea

to common stockholders 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.

ff

to Series A Preferred Stock
d Stock
to Series B Preferre

Net income (loss) attributable to Vistra
Less cumulative dividends attributablea
Less cumulative dividends attributablea
Net income (loss) attributable to common stock — basic
Weighted average shares of common stock outstanding — basic
Net income (loss) per weighted average share of common stock outstanding
— basic
Dilutive securities: Stock-based incentive compensation plan
Weighted average shares of common stock outstanding — diluted
Net income (loss) per weighted average share of common stock outstanding
— diluted

Year Ended December 31,

2021

2020

2019

(1,274) $
(17)
(4)
(1,295)
482,214,544

636
—
—
636
488,668,263

$

928
—
—
928
494,146,268

(2.69) $
—
482,214,544

1.30
2,422,205
491,090,468

$

1.88
5,789,223
499,935,490

(2.69) $

1.30

$

1.86

$

$

$

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the
would have been antidilutive totaled 14,412,299, 12,553,414 and 2,447,850 shares for the years ended December 31,

effect
ff
2021, 2020 and 2019, respectively.

118

10. ACCOUNTS RECEIVABLE FINANCING

Accounts Receivable Securitizat

iontt

tt

Program

TXU Energy Receivablea

s Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable finaff

ncing
facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers).
In
December 2020, the Receivables Facility was amended to include Ambit Texas, LLC (Ambit Texas), Value Based Brands and
TriEagle Energy, as originators, and increase the commitment of the Purchasers to $500 million for the remaining term of the
2021, the Receivables Facility was amended to allow for a one-time, $596 million borrowing
Receivabla es Facility. In February
to take advantage of a higher receivable balance at such time. The borrowing limit returned
to $500 million in March 2021. In
March 2021, the Receivables Facility was amended to increase the commitment of the Purchasers to $600 million through the
July 2021 renewal. The Receivables Facility was renewed in July 2021, extending the term of the Receivables Facility to July
2022, with the abila
ity to borrow $600 million beginning with the settlement date in July 2021 until the settlement date in August
2021, $725 million from the settlement date in August 2021 until the settlement date in November 2021 and $600 million from
the settlement date in November 2021 and thereafter forff

the remaining term of the Receivables Facility.

rr

t

s Facility), arising fromff

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands
and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivablea
s Facility (Originators), each sell
and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms
the sale of electricity to its customers and related rights (Receivables), to RecCo, a
of the Receivablea
consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain
a
conditions, and may draw under the Receivablea
to fund its acquisition of the
Receivabla es from the Originators. RecCo has granted a security interest on the Receivablea
s and all related assets for the benefit
of the Purchasers under the Receivablea
s Facility and Vistra Operations has agreed to guarantee the obligations under the
s Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term
agreements governing the Receivablea
s Facility are reflected as cash
borrowings on the consolidated balance sheets. Proceeds and repayments under the Receivablea
flows from financing activities in our consolidated statements of cash flows.
s transferred to the Purchasers remain
on Vistra's balance sheet and Vistra reflects a liabila
ity 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 Receivables on behalf of
.
RecCo and the Purchasers, as applicablea

s Facility up to the limits described above

Receivablea

ff

As of December 31, 2021, there were no outstanding borrowings under the Receivablea

s Facility. As of December 31,
s Facility totaled $300 million and were supported by $735 million of

2020, outstanding borrowings under the Receivablea
RecCo gross receivablea

s.

Repuee

rchase Faciliii tyii

In October 2020, TXU Energy and the other originators under the Receivablea

s Facility entered into a $125 million
repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In
July 2021, the Repurchase Facility was renewed until August 2021 and increased from $125 million to $150 million. In August
2021, the Repurchase Facility was renewed until July 2022 and the facility size was decreased from $150 million to $125
million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of
s Facility and representing a portion of the outstanding balance
TXU Energy for the benefit of Originators under the Receivablea
of the purchase price paid forff
s Facility. Under the
Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the
Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in
exchange for the returnt
of the Subordinated Note (collectively, the Transactions). Each Transaction is expected to have a term
of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer afteff

s sold by the Originators to RecCo under the Receivablea

r an event of default.

the Receivablea

TXU Energy and the other Originators have each granted Buyer a first-pri

ority security interest in the Subordinated Note
to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee
the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements
governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the schedule termination of the
Receivabla es Facility.

ff

There were no outstanding borrowings under the Repurchase Facility at both December 31, 2021 and December 31, 2020.

119

11. LONG-TERM DEBT

Amounts in the tablea

below represent the categories of long-term debt obligations incurred by the Company.

Vistra Operations Credit Facilities
Vistra Operations Senior Secured Notes:

3.550% Senior Secured Notes, due July 15, 2024
3.700% Senior Secured Notes, dued
4.300% Senior Secured Notes, dued

January 30, 2027
July 15, 2029
Total Vistra Operations Senior Secured Notes

Vistra Operations Senior Unsecured Notes:

5.500% Senior Unsecured Notes, due September 1, 2026
5.625% Senior Unsecured Notes, due February 15, 2027
5.000% Senior Unsecured Notes, due July 31, 2027
4.375% Senior Unsecured Notes, due May 15, 2029
Total Vistra Operations Senior Unsecured Notes

Other:

a

ity Agreements

Forward Capac
Equipment Financing Agreements
8.82% Building Financing due semiannually through February 11, 2022 (a)
Other

Total other long-term debt

Unamortized debt premiums, discounts and issuance costs
Total long-term debt including amounts due currently
Less amounts dued
Total long-term debt less amounts dued

currently

currently

December 31,

2021

2020

$

2,543

$

2,572

1,500
800
800
3,100

1,000
1,300
1,300
1,250
4,850

213
92
3
3
311
(73)
10,731
(254)
10,477

$

$

1,500
800
800
3,100

1,000
1,300
1,300
—
3,600

45
68
10
3
126
(68)
9,330
(95)
9,235

____________
(a) Obligation related to a corporate office space finance lease. This obligation will be funded

ff

by amounts held in an escrow

account that is refleff cted in current assets in our consolidated balance sheets.

Vistrii

a OperOO ations Credit Facilitll iett s

As of December 31, 2021, the Vistra Operations Credit Facilities consisted of up tu

o $5.268 billion in senior secured, first-
lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to
$2.725 billion, including a $2.35 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $2.543 billion
ing transactions and amendments completed in 2021, 2020 and
(Term Loan B-3 Facility). These amounts reflect the follow
2019:

ff

•

•

In March 2021, Vistra Operations borrowed $1.0 billion principal amount under the Term Loan A Facility. In April
2021, Vistra Operations borrowed an additional $250 million principal amount under the Term Loan A Facility.
Proceeds from the Term Loan A Facility, together with cash on hand, were used to repay certain amounts outstanding
under the Revolving Credit Facility. Borrowings under the Term Loan A Facility were reported in short-term
borrowings in our condensed consolidated balance sheet. In May 2021, Vistra Operations used the proceeds from the
2029 (described below), together with cash on
issuance of the Vistra Operations 4.375% senior unsecured notes dued
hand, to repay the $1.250 billion borrowings under the Term Loan A Facility. We recorded an extinguishment loss of
$1 million on the transaction in the nine months ended September 30, 2021.

In March 2020, Vistra Operations repurchased and cancelled $100 million principal amount of Term Loan B-3
Facility borrowings at a weighted average price of $93.875. We recorded an extinguishment gain of $6 million on
the transaction in the year ended December 31, 2020.

120

•

•

•

•

In November 2019, Vistra Operations used the net proceeds from the November 2019 Senior Secured Notes Offering
described below and $799 million of incremental borrowings under the Term Loan B-3 Facility to repay the entire
amount outstanding of $1.897 billion of term loans under the B-1 Facility (Term Loan B-1 Facility). Fees and
expenses related to the transactions totaled $2 million in the year ended December 31, 2019, which were recorded as
interest expense and other charges on the consolidated statements of operations.

In October 2019, Vistra Operations borrowed $550 million under the Revolving Credit Facility. The proceeds of the
borrowings were used for general corporate purposes, including the funding of a $425 million dividend to Vistra to
pay the principal, premium and interest due in connection with the redemption by Vistra of the entire $387 million
aggregate principal amount outstanding of 7.625% senior notes described below.
In November 2019, Vistra
Operations repaid $200 million under the Revolving Credit Facility.

In June 2019, Vistra Operations used the net proceeds from the June 2019 Senior Secured Notes Offerings (described
below) to repay $889 million under the Term Loan B-1 Facility, the entire amount outstanding of $977 million of
term loans under the B-2 Facility (Term Loan B-2 Facility, and together with the Term Loan B-1 Facility and the
Term Loan B-3 Facility, the Term Loan B Facility) and $134 million under the Term Loan B-3 Facility. We recorded
an extinguishment loss of $4 million on the transactions in the year ended December 31, 2019.

In March 2019 and May 2019, the Vistra Operations Credit Facilities were amended whereby we obtained $225
million of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by
$50 million. Fees and expenses related to the amendments to the Vistra Operations Credit Facilities totaled $2
million for the year ended December 31, 2019, which were capia talized as a noncurrent asset.

During the year ended December 31, 2021, we borrowed $1.450 billion and repaid $1.450 billion under the Revolving

Credit Facility, with proceeds from the borrowings used forff

general corporate purposes.

The Vistra Operations Credit Facilities and related availablea

a
capac

ity at December 31, 2021 are presented below.

December 31, 2021

Vistra Operations Credit Facilities

Revolving Credit Facility (a)
Term Loan B-3 Facility (b)

Maturity Date
June 14, 2023
December 31, 2025

Total Vistra Operations Credit Facilities

Facility
Limit

$

$

2,725
2,543
5,268

Cash
Borrowings
$

— $

Letters of Credit
Outstanding

Available
Capacity

2,543
2,543

$

$

1,471

1,471

$

$

1,254
—
1,254

___________
(a) Revolving Credit Facility used forff

general corporate purposes. The Facility includes a $2.35 billion letter of credit sub-
facility. Letters of credit outstanding reduce our available capacity. Cash borrowings under the Revolving Credit
Facility are reported in short-term borrowings in our consolidated balance sheets.

(b) Cash borrowings under the Term Loan B-3 Facility are subject to a required scheduled quarterly payment in annual
amount equal to 1.00% of the original principal amount with the balance paid at maturity. Amounts paid cannot be
reborrowed.

As of December 31, 2021, cash borrowings under the Revolving Credit Facility would bear interest based on applicable
LIBOR rates, plus a fixeff
d 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-3 Facility bears interest based on
spreads of 1.75%. As of December 31, 2021, the weighted average interest rates before
applicable LIBOR rates plus fixed
taking into consideration interest rate swapsa
on outstanding borrowings was 1.86% under the Term Loan B-3 Facility. 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 payablea
with respect to any unused portion of the availablea
Revolving Credit Facility.

ff

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.

ff

121

The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the
th in the Vistra Operations

Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forff
Credit Facilities.

The Vistra Operations Credit Facilities provide for affirmative and negative covenants appl

icable 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.

a

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default
resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties,
material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other
agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving
Credit Facility, and solely during
when the aggregate revolving
a compliance period (which, in general, is appli
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 Vistra Operations Credit Facilities, not to exceed
4.25 to 1.00. As of December 31, 2021, 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 payablea

, either automatically or at the election of specified lenders.

cablea

d

a

tt
Interes

t Rate Swaps — Vistra employs interest rate swapsa

to hedge our exposure to variable rate debt. As of

December 31, 2021, Vistra has entered into the folff

lowing series of interest rate swap ta

ransactions.

a
Swapped
Swapped
a
Swapped
a
Swapped
a
a
Swapped
a
Swapped

to fixed
to variable
to fixed (a)
to variable
to fixed (b)
to variable (b)

Notional Amount
$3,000
$700
$720
$720
$3,000
$700

Expiration Date
July 2023
July 2023
February 2024
2024
rr
February

July 2026
July 2026

Rate Range
3.67 % - 3.91%
3.20 % - 3.23%
3.71 % - 3.72%
3.20 % - 3.20%
4.72 % - 4.79%
3.28 % - 3.33%

(a)

In June 2018, we completed the novation of $1.959 billion of Vistra (legacy Dynegy) interest rate swapsa
Operations, of which $398 million expired and $841 million were terminated in June 2019.

to Vistra

(b) Effective from July 2023 through July 2026.

During 2019, Vistra entered into $2.12 billion of new interest rate swaps,a

and receive a fixeff
offsetting the hedge of the existing swapsa
settle over time, in accordance with the original contractual
exposure on $2.30 billion of debt through July 2026.

t

d rate. The terms of these new swaps were matched against the terms of certain existing swaps,a

and fixing the out-of-the-money position of such swaps.a

pursuant to which Vistra will pay a variable rate
effectively
These matched swapsa will
continue to hedge our

terms. The remaining existing swapsa

122

Commodity-Ltt

inked Revolvill ngii Credit Facilitll ytt

r

On February

4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra
Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent
and collateral agent. The Credit Agreement provides forff
a $1.0 billion senior secured commodity-linked revolving credit
facility (the Commodity-Linked Facility). Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly
basis based on a set of theoretical transactions which approximate the hedge portfolio of Vistra Operations and certain of its
subsidiaries in certain power markets, with availability thereunder not to exceed the facility limit nor be less than zero. Vistra
Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if
outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce
outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use the liquidity provided
under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra
Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capita
al and general
corporate purposes.

Secured Lettertt

of Credit Faciliii tiii es

In August and September 2020, Vistra entered into uncommitted standby letter of credit facilities that are each secured by
a first
lien on substantially all of Vistra Operations' (and its subsidiaries') assets (which ranks pari passu with the Vistra
ff
Operations Credit Facilities) (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC
Facilities are used for general corporate purposes.
In October 2021, Vistra entered into an additional Secured LOC Facility
which will also be used for general corporate purposes. As of December 31, 2021, $406 million of letters of credit were
outstanding under the Secured LOC Facilities.

rr
Altertt nate

Lettertt

of Credit Faciliii tiii es

Two alternate letter of credit facilities (each, an Alternate LOC Facility) became effective in the years ended December
ility limit of $250 million matured in
ility limit of $250 million matured in December

31, 2018 and 2019, respectively. One Alternate LOC Facility with an aggregate facff
December 2020. The remaining Alternate LOC Facility with an aggregate facff
2021.

tt
Vistra Operat
ions
OO

Senior Secured NotesNN

In 2019, Vistra Operations issued and sold $3.1 billion aggregate principal amount of senior secured notes (June 2019
Senior Secured Notes and the November 2019 Senior Secured Notes) in offerings (the June 2019 Senior Secured Notes
Offering and the November 2019 Senior Secured Notes Offering) to eligible purchasers under Rule 144A and Regulation S
under the Securities Act consisting of the folff

lowing:

Senior Secured Notes

3.550% Senior Secured Notes
3.700% Senior Secured Notes
4.300% Senior Secured Notes
Total senior secured notes

Net proceeds
Debt issuance and other fees (c)

Maturity
Year
2024
2027
2029

Interest Terms
(Due Semiannually in Arrears)
January 15 and July 15
January 30 and July 30
January 15 and July 15

June 2019
Senior Secured
Notes Offering (a)
1,200
$
—
800
2,000
1,976
20

$
$
$

November 2019
Senior Secured
Notes Offering (b)
300
$
800
—
1,100
1,099
10

$
$
$

___________
(a) The June 2019 Senior Secured 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, together with cash on hand, were used to prepay certain amounts outstanding and
accrued interest (together with feeff

s and expenses) under the Term Loan B Facility.
(b) The November 2019 Senior Secured 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, together with borrowings under the Term Loan B-3 Facility and cash on hand,
were used to repay the entire amount outstanding and accrued interest (together with fees and expenses) under the Term
Loan B-1 Facility.

123

(c) Capita

alized as a reduction in the carrying amount of the debt.

The indenturet

(as may be amended or supplemented fromff

time to time, the Vistra Operations Senior Secured Indenture)
governing the June 2019 Senior Secured Notes and the November 2019 Senior Secured Notes (collectively, the Senior Secured
the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also
Notes) provides forff
guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-pri
ority security interest in
the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities, which consists of a
substantial portion of the property, assets and rights owned by Vistra Operations and certain direct and indirect subsidiaries of
Vistra Operations as subsidiary guarantors (collectively, the Guarantor Subsu idiaries) as well as the stock of Vistra Operations
held by Vistra Intermediate. The collateral securing the Senior Secured Notes will be released if Vistra Operations' senior,
unsecured long-term debt securities obtain an investment grade rating fromff
two out of the three rating agencies, subject to
reversion if such rating agencies withdraw the investment grade rating of Vistra Operations' senior, unsecured long-term debt
securities or downgrade such rating below investment grade. The Vistra Operations Senior Secured Indenturet
contains certain
covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as
applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

ff

t

tt
Vistra Operat
ions
OO

Senior Unsecured NotesNN

In 2019 and 2021, Vistra Operations issued and sold $3.9 billion aggregate principal amount of senior unsecured notes in
offerings (the February 2019 Senior Unsecured Notes Offering, June 2019 Senior Unsecured Notes Offerings and the May 2021
Senior Unsecured Offerings) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of
the following:

Maturity
Year
2027
2027
2029

Interest Terms
(Due Semiannually in Arrears)
February 15 and August 15
January 31 and July 31
May 1 and November 1

Senior Unsecured Notes
5.625% Senior Unsecured Notes
5.000% Senior Unsecured Notes
4.375% Senior Unsecured Notes

Total
Net Proceeds
Debt issuance and other fees (d)

February 2019
Senior Unsecured
Notes Offering (a)
1,300
—
—
1,300 $
1,287 $
16 $

June 2019
Senior Unsecured
Notes Offering (b)
—
1,300
—
1,300 $
1,287 $
13 $

May 2021
Senior Unsecured
Notes Offering (c)
—
—
1,250
1,250
1,235
15

$
$
$

___________
(a) The 5.625% senior unsecured notes dued

2027 (the Februar

019 Senior Unsecured Notes) were sold pursuant to a
purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P. Morgan Securities LLC., as
representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to pay the purchase
019 Tender
price and accrued interest (together with fees and expenses) required in connection with (i) the Februarr
Offer, (defined below) and (ii) the redemption of approximately $35 million aggregate principal amount of our 7.375%
senior unsecured notes dued
2022 (7.375% senior notes) and approximately $25 million aggregate principal amount of our
outstanding 8.034% senior unsecured notes dued

2024 (8.034% senior notes).

ry 2rr

ry 2rr

(b) The 5.000% senior unsecured notes dued

2027 (the June 2019 Senior Unsecured Notes) were sold pursuant to a purchase
agreement by and among Vistra Operations, the Guarantor Subsidiaries and Goldman Sachs & Co. LLC, as representative
of the several initial purchasers. Net proceeds, 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 June 2019 Tender Offer (defined
below) and (ii) the redemption of approximately $306 million of our outstanding 7.375% senior notes and approximately
$87 million of our 7.625% senior unsecured notes dued
2024 (7.625% senior notes) in July 2019. We recorded an
extinguishment gain of $2 million on the redemptions in the year ended December 31, 2019

(c) The 4.375% senior unsecured notes dued

2029 (the May 2021 Senior Unsecured Notes) were sold pursuant to a purchase
the Guarantor Subsidiaries and J.P. Morgan Securities LLC., as
agreement by and among Vistra Operations,
representative of the several initial purchasers. Net proceeds. together with cash on hand, were used to pay all amounts
outstanding under the Term Loan A Facility and to pay feeff

s and expenses of $15 million related to the offering.

(d) Capitalized as a reductd

ion in the carrying amount of the debt.

124

Since 2018, Vistra Operations has issued and sold $4.850 billion aggregate principal amount of senior unsecured notes in
offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indentures governing the May
2021 Senior Unsecured Notes, the June 2019 Senior Unsecured Notes, the Februarr
019 Senior Unsecured Notes and the
2026 (collectively, as each may be amended or supplemented from time to time, the Vistra
5.500% senior unsecured notes dued
provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the
Operations Senior Unsecured Indentures)
t
punctual
contain
payment of the principal and interest on such notes. The Vistra Operations Senior Unsecured Indentures
t
certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries,
as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

ry 2rr

t

ee
Debt Repurc

hase Program

In July 2019, the Board authorized up to $1.0 billion to repay or repurchase any outstanding debt of the Company (or its
subsidiaries). Through April 2020, $684 million of debt had been repurchased under the $1.0 billion July 2019 authorization,
including the repurchase of $100 million principal amount of Term Loan B-3 Facility borrowings discussed above and the
redemption of $81 million aggregate principal amount outstanding of 8.000% senior unsecured notes dued
2025 (8.000% senior
notes) discussed below. In April 2020, the Board authorized up to $1.0 billion to repay or repurchase additional outstanding
debt, with this new authority superseding and replacing the $316 million of availability under the previously authorized $1.0
billion debt repurchase program. Through December 31, 2021, approximately $666 million had been repurchased under the
$1.0 billion April 2020 authorization, consisting of the redemption of the Vistra 5.875% senior unsecured notes dued
2023
2026 (8.125% senior notes), each as
(5.875% senior notes) and the redemption of the Vistra 8.125% senior unsecured notes dued
described below.

SS
Vistra Senio

r UnseUU cured NotesNN

On the Merger Date, Vistra assumed $6.138 billion principal amount of Dynegy's senior unsecured notes (Vistra Senior
In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities

Unsecured Notes).
(and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding.

The following amounts reflect redemption, repurchase and tender offer transactions completed in 2019 and 2020. Vistra

had no outstanding senior notes at the Parent level as of December 31, 2021 and 2020.

Vistra Senior Unsecured Notes

6.750%Senior Unsecured Notes
7.375% Senior Unsecured Notes
5.875% Senior Unsecured Notes
7.625% Senior Unsecured Notes
8.034% Senior Unsecured Notes
8.000% Senior Unsecured Notes
8.125%Senior Unsecured Notes

Total

Extinguishment gain/(loss)

Maturity
Year
2019
2022
2023
2024
2024
2025
2026

February 2019
Tender Offer
(a)

June
2019 Tender
Offer (b)

2019
Redemptions
(c)

2020
Redemptions
(d)

$

$
$

— $

1,193
—
—
—
—
—
1,193 $
7 $

— $
173
—
672
—
—
—
845
7

$
$

— $
341
—
475
25
—
—
841
11

$
$

—
—
500
—
—
81
166
747
11

____________
(a)

In February 2019, Vistra used the net proceeds from the Februar
tender offer (the February
senior notes.

019 Senior Unsecured Notes Offering to fund a cash
2019 Tender Offer) to purchase for cash $1.193 billion aggregate principal amount of 7.375%

y 2rr

rr

r

(c)

(b) In June 2019, Vistra used the net proceeds from the June 2019 Notes Offering to fund a cash tender offer (the June 2019
Tender Offer) to purchase for cash $173 million of 7.375% senior notes and $672 million of 7.625% senior notes. In July
2019, Vistra accepted and settled an additional approximately $1 million aggregate principal amount of outstanding
7.625% senior notes that were tendered after the early tender date of the June 2019 Tender Offer.
In November 2019, Vistra redeemed $387 million aggregate principal amount outstanding of 7.625% senior notes at a
redemption price equal to 103.8% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but
excluding, the date of redemption (the 2019 Redemption). Vistra redeemed $341 million, $87 million and $25 million
aggregate principal amount of 7.375% senior notes, 7.625% senior notes and 8.034% senior notes, respectively, using
proceeds from the February
2019 Senior Unsecured Notes Offering and the June 2019 Senior Unsecured Notes Offerings
discussed above.

rr

125

(d) In January 2020, June 2020 and July 2020, Vistra redeemed aggregate principal amounts of $81 million of 8.000% senior
notes, $500 million of 5.875% senior notes and $166 million of 8.125% senior notes, respectively, at redemption prices of
104%, 100.979% and 104.063%, respectively, of the aggregate principal amounts thereof, plus accrued and unpaid
interest to, but excluding, the dates of redemption (the 2020 Redemptions, and together with the 2019 Redemption, the
Redemptions).

February 2019 Consent Solicitation — In connection with the February

rr

2019 Tender Offer, Vistra also commenced
holders of the 7.375% senior notes. Vistra received the requisite consents from the holders of the
governing these senior notes to, among other things, eliminate substantially all

solicitation of consents fromff
7.375% senior notes and amended the indenturet
of the restrictive covenants and certain events of default.

Other Long-TermTT

Debt

Amortizing Notes — On the Merger Date, Vistra assumed the obligations of Dynegy's senior unsecured amortizing note
(Amortizing Notes) that maturet
d on July 1, 2019. The Amortizing Notes were issued in connection with the issuance of the
tangible equity units (TEUs) by Dynegy (see Note 14). Each installment payment per Amortizing Note was paid in cash and
constituted a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00%.
Interest was
calculated on the basis of a 360-day year consisting of twelve 30-day months. Payments were applied first to the interest due
(Amortizing Notes
and payablea
and the Amortizing
t
Indenture).
Notes Indenturet

and then to the reduction of the unpaid principal amount, allocated as set forth in the indenturet
On the maturity date, the Company paid all amounts due under the Amortizing Notes Indenturet

ceased to be of further force

and effecff

t.

ff

Forward Capacity Agreementstt — In March 2021, the Company sold a portion of the PJM capac

Planning Years 2021-2022 to a finaff
will receive capacity payments fromff
We will continue to be subject to the performanc
payments forff
of approximately 4.25%.

ff

t

ity that cleared for
ncial instituti
on (2021-2022 Forward Capacity Agreement). The buyer in this transaction
PJM during the Planning Years 2021-2022 in the amount of approximately $515 million.
e obligations as well as any associated performance penalties and bonus
as a debt issuance with an implied interest rate

a

those planning years. As a result, this transaction is accounted forff

On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM
capac
on (Legacy
ity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a finaff
a
Forward Capacity Agreements, and, together with the 2021-2022 Forward Capacity Agreement, the Forward Capacity
In May 2021, the final capacity payment from PJM during the Planning Years 2020-2021 was paid, and the
Agreements).
terms of the Legacy Forward Capacity were fulfilled.

ncial instituti

tt

i
Equipment

Financing Agreements — On the Merger Date, the Company assumed the obligation of Dynegy's agreements
our gas-fueled generation fleet, we have obtained parts and
under which we receive maintenance and capital improvements forff
equipment intended to increase the output, efficiency and availability of our generation units. We financed these parts and
equipment under agreements with maturit

ies ranging from 2021 to 2026.

t

Mandatorily Rll

k — In October 2019, PrefCo voluntarily redeemed the entire $70
million aggregate principal amount outstanding of its authorized preferred stock at a price per share equal to the preferred
liquidation amount, plus accrued and unpaid dividends to and including the date of redemption.

edeedd mable Subsidiary Pr

ff
referre

d StocSS

Debt Assumed in CriCC us Transaction — On the Crius Acquisition Date, Vistra assumed $140 million in long-term debt

obligations in connection with the Crius Transaction consisting of the folff

lowing:

•
•

•

$44 million of 9.5% promissory notes due July 2025 (2025 promissory notes);
$8 million of 2% Connecticut Department of Economic and Community Development (CT DECD) term loans due
February 2rr
$88 million of borrowings and $9 million of issued letters of credit under the legacy Crius credit facility.

027; and

In
In July 2019, borrowings of $88 million under the legacy Crius credit facility were repaid using cash on hand.
November 2019, (i) borrowings of approximately $38 million under the 2025 promissory notes were repaid using cash on hand
and (ii) borrowings of approximately $2 million were offset by legacy indemnification obligations of the holders of the 2025
promissory notes.
In November 2019, borrowings of $8 million under the Connecticut Department of Economic and
Community Development term loans were repaid using cash on hand.

126

Maturitiett s

Long-term debt maturities at December 31, 2021 are as follows:

2022
2023
2024
2025
2026
Thereafter
Unamortized premiums, discounts and debt issuance costs
Total long-term debt, including amounts due currently

LEASES

December 31, 2021
258
$
40
1,540
2,470
1,006
5,490
(73)
10,731

$

Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease
o 15 years. Certain leases also contain options to terminate the

terms for 1 to 36 years. Our leases include options to renew up tu
lease.

Lease Cost

The following tablea

presents costs related to lease activities:

Operating lease cost
Finance lease:

Finance lease right-of-use asset amortization
Interest on lease liabilities
Total finance lease cost

Variablea
lease cost (a)
Short-term lease cost
Sublease income (b)
Net lease cost

Year Ended December 31,

2021

2020

2019

$

11

$

14

$

9
10
19
29
35
(7)
87

$

7
7
14
29
31
(8)
80

$

$

14

4
4
8
26
19
(8)
59

____________
(a) Represents coal stockpile management services, common area maintenance services and rail car payments based on the

number of rail cars used.

(b) Represents sublease income related to real estate leases.

127

Balance SheSS et Infon rmation

The following tablea

presents lease related balance sheet information:

Lease assets:

Operating lease right-of-use assets
Finance lease right-of-use assets (net of accumulated depreciation)

Total lease right-of-use assets

Current lease liabila

ities:

Operating lease liabia lities
Finance lease liabilities

Total current lease liabila

ities

Noncurrent lease liabilities:
Operating lease liabila
ities
Finance lease liabilities

Total noncurrent lease liabila
Total lease liabilities

ities

Cash FlowFF

s aw nd Other Information

The following tablea

presents lease related cash flows

ff

and other information:

December 31,

2021

2020

$

$

$
$

40
173
213

5
8
13

38
235
273
286

$

Cash paid for amounts included in the measurement of lease liabila

ities:

Operating cash flows fromff
Operating cash flows from finance leases
Finance cash flows fromff

finance leases

operating leases

Non-cash disclosure upon commencement of new lease:

Right-of-use assets obtained in exchange for new operating lease
liabilities
Right-of-use assets obtained in exchange for new finance lease liabilities

Non-cash disclosure upon modification of existing lease:
Modification of operating lease right-of-use assets
Modification of finance lease right-of-use assets

ightedtt Average Remaininii

g Ln

ease Term

Year Ended December 31,

2021

2020

2019

$

$

11
9
5

7
—

(4)
(1)

$

17
5
10

14
108

(1)
23

45
182
227

8
8
16

40
206
246
262

17
4
4

95
13

(41)
50

The following tablea

presents weighted average remaining lease term information:

Weighted average remaining lease term:

Operating lease
Finance lease

Weighted average discount rate:

Operating lease
Finance lease

128

December 31,

2021

2020

17.6 years
25.0 years

12.3 years
24.2 years

5.76%
4.95%

5.80 %
4.92 %

Maturity ott

f Lo

ease Liabiliii tiii es

The following tabla e presents maturity of lease liabilities:

2022
2023
2024
2025
2026

Thereafter
Total lease payments

Less: Interest

Present value of lease liabila

ities

13. COMMITMENTS AND CONTINGENCIES

Contractual Commitmii

ents

Operating Lease
6
$
7
4
3
3
51
74
(31)
43

$

Finance Lease
17
16
17
17
14
369
450
(207)
243

$

$

$

$

Total Lease

23
23
21
20
17
420
524
(238)
286

As of December 31, 2021, we had minimum contractual
ff

contracts, energy-related contracts, leases and other agreements as foll

commitments under long-term service and maintenance
ows.

t

2022
2023
2024
2025
2026
Thereafter
Total

Long-Term Service
and Maintenance
Contracts (a)

Coal transportation
agreements

Pipeline transportation
and storage reservation
fees

Water
Contracts

$

$

202
268
236
207
196
2,130
3,239

$

$

104
22
24
25
26
27
228

$

$

86
54
40
36
23
91
330

$

$

9
9
9
9
9
58
103

____________
(a) Long-term service and maintenance contracts reflect expected expenditures

t

as these contracts do not include minimum

spending requirements, but can only be terminated based on events outside the control of the Company.

In addition to the commitments detailed above

a

, we have nuclear fuel

ff

contracts with early termination penalties. As of

December 31, 2021, termination costs of $54 million would be incurred if we terminated those contracts.

Expenditures

t

under our coal purchase and coal transportation agreements totaled $850 million, $845 million, and $1.092

billion for the years ended December 31, 2021, 2020 and 2019, respectively.

s
Guaranteett

We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment

under certain conditions. Material guarantees are discussed below.

129

Letters orr

f Co

redCC itdd

As of December 31, 2021, we had outstanding letters of credit totaling $1.877 billion as follows:

•

•
•
•
•

$1.558 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/RTOs;
$157 million to support battery and solar development projects;
$27 million to support executory contracts and insurance agreements;
$74 million to support our REP finaff
$61 million for other credit support requirements.

ncial requirements with the PUCT; and

Surety Bonds

As of December 31, 2021, we had outstanding surety bonds totaling $561 million to support performff

ance under various

contracts and legal obligations in the normal course of business.

i
Litiii gati

on and Regulatll orytt

Proceedings

ii

Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that
we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to
participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when
information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated.
As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as
incurred. Management has assessed each of the following legal matters based on current information and made a judgment
of damages sought, and the
concerning its potential outcome, considering the naturet
probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonablya
estimate the
scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of
operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and
to inherent
estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject
uncertainties and unfavorablea
rulings or developments, it is possible that the ultimate resolution of these matters could be at
amounts that are different from our currently recorded reserves and that such differences could be material.

of the claim, the amount and naturet

i

Gas Index Pricing Litigati

on — We, through our subsidiaries, and other 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 plaintiffs in these cases allege that the defendants
engaged in an antitrust conspiracy to inflate natural
gas prices during the relevant time period and seek damages under the
respective state antitrust statutes. In December 2021, we settled an individual action with Reorganized FLI, Inc., as successor
to Farmland Industries, Inc., that was pending in Kansas fede
ral court, and that case has now been dismissed. We remain as a
defendant in one other action, which is a consolidated putative class action lawsuit pending in federal court in Wisconsin.

ff

t

t

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.
In March 2018, BNSF Railway Company
(BNSF) and Norfolk Southern Railway Company (NS) filed a demand for arbitration. In March 2021, the parties entered into a
In connection with that settlement,
confidential settlement to resolve this matter and the Coffeen matter discussed below.
BNSF and NS dismissed with prejudice their arbitration disputes forff Wood River and Coffeen and these matters are fully
resolved.

130

o

Coffeen

and Duck CreekCC

Rail Disputes — In April 2020, IPH, LLC (IPH) received notification that BNSF and NS were
initiating dispute resolution related to IPH's suspension of its Coffeen Rail Transportation Agreement with the railroads, and
Illinois Power Resources Generating, LLC (IPRG), received notification that BNSF was initiating dispute resolution related to
In November 2019, IPH and IPRG sent
IPRG's suspension of its Duck Creek Rail Transportation Agreement with BNSF.
suspension notices to the railroads asserting that the MPS rule requirement to retire at least 2,000 megawatts of generation (see
discussion below) was a change-in-law under the agreement that rendered continued operation of the plants no longer
sible. In addition, IPH and IPRG asserted that the MPS rule's retirement requirement also qualified as a force
economically feaff
In March 2021, we entered into a confidential settlement
majeua
agreement with BNSF to resolve the Duck Creek matter and a separate confidential settlement agreement with BNSF and NS to
resolve the Coffeen and Wood River matter discussed above. BNSF has dismissed with prejudice the Duck Creek arbitration
dispute and this matter is now fully resolved. The settlement of these rail disputes did not have a material impact on our
financial statements.

re event under the agreements excusing performance.

Wintertt Stormtt

e
Uri Legal

Proceedings

e

Reprici

In our brief, we argue that the prior PUCT rushed

ng Challenges — In March 2021, we filed an appeal in the Third Court of Appeals in Austin, Texas (Third Court
of Appeals), challenging the PUCT's February 15 and February 16, 2021 orders governing ERCOT's determination of
wholesale power prices during load-shedding events. We filed our opening brief in June 2021, and response briefs were filed in
that dramatically raised the price of
September 2021.
the PUCT to undertake an
electricity in ERCOT, but in doing so failed to follow any of the rulemaking procedures required forff
emergency rulemaking, and we have asked the court to vacate this rulerr
. Other parties also filed briefs in support of our
challenge to the PUCT's orders. In addition, we have also submitted settlement disputes with ERCOT over power prices and
other issues during
Winter Storm Uri. Following an appeal of the PUCT's March 5, 2021 verbal order and other statements
made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with
l decision on whether to reprice and that we and
the Third Court of Appeals that the PUCT has not prejudged or made a finaff
other parties may continue disputing the pricing through the ERCOT process.

to adopt a rulerr

d

r

rr

Koch Disputes — In March 2021, we filed a lawsuit in Texas state court against Odessa-Ector Power Partners, L.P., Koch
relief in
Resources, LLC, Koch AG & Energy Solutions, LLC, and Koch Energy Services, LLC (Koch) seeking equitablea
which we contested the amount of the February
2021 earnout payment under the terms of the 2017 asset purchase agreement
(APA) with Koch. Koch subsequently filed its own related lawsuit in Delaware Chancery Court, and the Delaware Chancery
Court ruled that all claims related to the APA dispute (including our equitablea
claims) would proceed in Delaware. We
021 earnout payment as an unjust windfall and inconsistent with
contested Koch's demand for $286 million for the February 2rr
the parties' intent when they entered into the APA in 2017. We recorded a $286 million liability in other noncurrent liabilities
and deferred
credits in our consolidated balance sheets. In March 2021, we also filed a lawsuit in New York state court against
ff
Koch for breach of contract and ineffective notice of force majea ure related to Koch's failure to deliver contracted-for quantities
In November 2021, the disputes we had with Koch
of gas during Winter Strom Uri, which Koch removed to federal court.
were resolved to the parties' mutual satisfact
ion and all the lawsuits have been dismissed. The matter was resolved within the
amount that was reserved and will be paid in the second quarter of 2022.

ff

i

e

Regulat

ory Investigations and Other Litigati

on Matters — Following the events of Winter Storm Uri, various regulatory
bodies, including ERCOT, the ERCOT Independent Market Monitor, the Texas Attorney General, the FERC and the NRC
initiated investigations or issued requests for information of various parties related to the significant load shed event that
occurred during the event as well as operational challenges forff
generators arising from the event, including performance and
fuel and supply issues. We responded to all those investigatory requests. In addition, a number of personal injury and wrongful
death lawsuits related to Winter Storm Uri have been filff ed in various Texas state courts against us and numerous generators,
transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants requested that
all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL)
pretrial judge.
In June 2021, the MDL panel granted the request to consolidate all these cases into a MDL for pretrial
022, an insurance subrogation lawsuit was filed in Austin state court by over one hundred
proceedings. In addition, in January 2rr
insurance companies against ERCOT, Vistra and several other defendants. The lawsuit seeks recovery of insurance funds paid
out by these insurance companies to various policyholders for claims related to Winter Storm Uri. We believe we have strong
defenses to this lawsuit and the other tort lawsuits and intend to defend against these cases vigorously.

131

Climate Change

nd the Environment and Restoring Science to Tackl

In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public
(the Environment Executive Order) which
Health att
directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take
action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions
discussed below are now subject to this review.

e the Climate Crisisii

TT

Greenhouse Gas Emissions (GHG)HH

Clean Energy (ACE) rule. The ACE ruler

to that repealed the Clean Power Plan (CPP) that had been finaff

In July 2019, the EPA finalized a ruler
lized in 2015 and
shed new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the
establia
developed emission guidelines that states must use when developing plans
Affordablea
In response to challenges brought by
to regulate GHG emissions from existing coal-fueled electric generating units.
the District of Columbia Circuit (D.C. Circuit Court)
Environmental groups and certain states, the U.S. Court of Appeals forff
vacated the ACE ruler
, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. In
October 2021, the U.S. Supreme Court granted four petitions for certiorari of the D.C. Circuit Court's decision and consolidated
the cases for review. The case is now fully briefed and scheduled for oral argument in February 2022. Additionally, in January
2021, the EPA, just prior to the transition to the Biden administration, issued a finaff
a significant contribution
finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. In
and remand of the GHG
April 2021, the D.C. Circuit Court granted the EPA's unopposed motion for voluntary vacaturt
significant contribution rule. The ACE ruler
and the rule on significant contribution are subject to the Environment Executive
Order discussed above.

setting forth

l rulerr

ff

PP
Regie onal Haze — Reasonable Pll

rogress

and Best Availabl

e Rll

ii

tt
etrofit

Technology (BARBB T) for Texas

ee

l ruler

addressing BART forff

In October 2017, the EPA issued a finaff

Texas electricity generation units, with the rule
serving as a partial approval of Texas' 2009 State Implementation Plan (SIP) and a partial Federal Implementation Plan (FIP).
For SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a
to a CSAPR trading program. The program includes 39 generating units (including the Martin Lake, Big
ff
similar fashion
Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program
started on January 1, 2019. For NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the
ruler
In
but also included additional revisions that were
August 2020, the EPA issued a finaff
proposed in November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit
, and the retirements of our
Court, where we have intervened in support of the EPA. We are in compliance with the ruler
Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply. The BART rulerr
is subject to the
Environment Executive Order discussed above, and the EPA has stated it is starting a proceeding for reconsideration of the
BART rule. The challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's action on reconsideration.

approved Texas's SIP that determines that no electricity generation units are subject to BART forff

affirming the prior BART finaff

particulate matter.

l rulerr

l ruler

132

SO2 Designations for Texas

u

u

In December 2017, the TCEQ submi

tted a petition for reconsideration to the EPA.

the Fifth Circuit (Fifthff Circuit Court). Subsequent

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation
plant and our now-retired Big Brown and Monticello 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 U.S. Court of Appeals forff
ly, 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
In August 2019, the
nonattainment rule.
EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous
nonattainment designations and each area at issue would be designated unclassifiablea
In August 2020, the EPA issued a
.
Finding of Failure for Texas to submit an attainment plan. In May 2021, the EPA finalized a "Clean Data" determination for
the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring
data supporting an attainment designation.
In June 2021, the EPA published two notices; one that it was withdrawing the
August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to
reconsider the original nonattainment designations. We, along with the State of Texas, challenged that EPA action and have
consolidated it with the pending challenge in the Fifth Circuit Court, with the matter likely being fully briefed by March 2022.
In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed
order to reduce SO2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduces emission
limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. The
TCEQ's SIP action was finalized in February 2022 and will be submitted to the EPA forff

review and approval.

Effluff ent Limitati

tt

on Guidelines

ll

(ELGs)GG

ff

In November 2015, the EPA revised the ELGs forff

steam electricity generation facilities, which will impose more stringent
ation (FGD), fly ash, bottom
standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfuriz
ash and flue gas mercury control wastewaters. Various parties filff ed petitions for review of the ELG rulrr e, and the petitions were
consolidated in the Fifth Circuit Court.
In April 2017, the EPA granted petitions requesting reconsideration of the ELG rulrr e
and administratively stayed the rule's compliance date deadlines. In August 2017, the EPA announced that its reconsideration
of the ELG rulrr e would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the
agency subsequently postponed the earliest compliance dates in the ELG rulrr e forff
cation of effluent limitations for FGD
and bottom ash wastewaters. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in
abeyance challenges to those effluent limitations. The remainder of the case proceeded, and in April 2019 the Fifth Circuit
pertaining to effluent limitations for legacy wastewater and
Court vacated and remanded portions of the EPA's ELG ruler
leachate. The EPA published a finaff
both FGD and bottom ash
transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rulrr e
ilities certifying that units will retire by December 2028 provided certain
allows for a retirement exemption that exempts facff
review of the new ELG revisions, and
effluent limitations are met.
Vistra subsidiaries filff ed a motion to intervene in support of the EPA in December 2020. In July 2021, the EPA announced its
intent to revise the ELG rulerr
and moved to hold the 2020 ELG revision litigation in abeyance pending the EPA's completion of
its reconsideration rulemaking. Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption
for applicable coal plants by the regulatory deadline of October 13, 2021.

In November 2020, environmental groups petitioned forff

in October 2020 that extends the compliance date forff

a
the appli

l ruler

CC
Coal Combust

iontt

Residuals (CCR)/Groundw

R

ater

In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR
establishing a
rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a finaff
deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final ruler
allows a
generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a
conversion to comply with the CCR rulrr e is underway or retirement will occur by either 2023 or 2028 (depending on the size of
the impoundment at issue). Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance
extensions under both conversion and retirement scenarios. In November 2020, environmental groups petitioned for review of
in the D.C. Circuit Court, and Vistra subsidiaries fileff d a motion to intervene in support of the EPA in December 2020.
this rulerr
Also, in November 2020, the EPA finalized a rulerr
that would allow an alternative liner demonstration for certain qualifying
facilities. In November 2020, we submitted an alternate liner demonstration for one CCR unit at Martin Lake. In August 2021,
we submitted a request to transferff
owing
022, the EPA determined that our conversion and
announcement that Zimmer will close by May 31, 2022.
retirement applications for our CCR facff
determination on any of those
applications.

In January 2rr
ilities were complete but has not yet made a final

our conversion application for the Zimmer facility to a retirement application foll

l ruler

ff

ff

133

MISO — 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. These violation notices
remain unresolved; however, 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 have completed closure activities at those ponds at our Baldwin facility.

a

In May 2018, Prairie Rivers Network (PRN)RR

At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR ruler

until the aforementioned
D.C. Circuit Court decision in August 2018, 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, and we submitted revised plans in
2014. In May 2017, in response to a request from the IEPA forff
additional information regarding the closure of these Vermilion
surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing
filed a citizen suit in federal court in Illinois against DMG, alleging
options.
In August 2018, we filed a motion to dismiss the
violations of the Clean Water Act for alleged unauthorized discharges.
lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. In June
the Seventh Circuit affirmed the district court's dismissal of the lawsuit, but stated that PRN
2021, the U.S. Court of Appeals forff
may refile. In April 2019, PRN aRR
allegedly
associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and
Illinois groundwater standards dating back to 1992. We answered that complaint in July 2021, and this matter remains in the
very early stages.

lso filff ed a complaint against DMG before the IPCB, alleging that groundwater flows

ff

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, which is owned by our subsidiary DMG, and that notice was referredr
to the
Illinois Attorney General.
In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filff ed a
complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation
notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic
river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim
consent order, DMG is required to evaluate the closure alternatives under the requirements of the newly implemented Illinois
Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during
the impoundment closure process, impacted groundwater will be collected beforff e it leaves the site or enters the nearby
Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a
certain distance of the impoundments. These proposed closure costs are reflecff
ted in the ARO in our condensed consolidated
balance sheets (see Note 21).

d

In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state
requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a
series of guidelines, rules and permit requirements for closure of ash ponds. Under the final rulr e, which was finalized and
became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the
IEPA for the selection of the best method for coal ash remediation at a particular site. The rulerr
does not mandate closure by
removal at any site. In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final
We filff ed our opening brief in October 2021. Other parties have also filed appeals of certain provisions of the final rulrr e.
rr
rule.
In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed
construction permit applications for three of our sites in January 2022.

ilities, we may incur significant costs that could have a material adverse effect

For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are
on our
required at any of our coal-fueled facff
financial condition, results of operations, and cash flows. The Illinois coal ash rule was finali
zed in April 2021 and does not
require removal. However, the rule will require us to undertake further site specific evaluations required by each program. We
will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be
ications have been submitted and approved by the IEPA. However, the
required under the Illinois rule until permit appl
currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO liabilities, reflect
the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the
environment for each location.

a

ff

ff

134

MISO 2015-2016 Plannll

ing Resource Auction

t

In May 2015, three complaints were filff ed at FERC regarding the Zone 4 results forff

the 2015-2016 planning resource
auction (PRA)RR 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. (Complainants), challenged the results of the PRA aRR
s
unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structuret
going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4
The Independent Market Monitor for MISO (MISO IMM), which was
constituti
responsible for monitoring the PRA,RR determined that all offers were competitive and that no physical or economic withholding
occurred. The MISO IMM also stated, in a filff ing responding to the complaints, that there is no basis for the remedies sought by
the Complainants. We filed our answer to these complaints explaining that we complied full
y with the terms of the MISO tariff
nd disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at
in connection with the PRA aRR
FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint
with respect to Dynegy's conduct alleged in the complaint.

ng market manipulation in the PRA.RR

ff

In October 2015, FERC issued an order of nonpublic, formal investigation (the investigation) into whether market

manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA.RR

In December 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff
provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the
Complainants regarding the PRA aRR
nd stated that those issues remained under consideration and would be addressed in a future
order.

ff

In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation
d that Dynegy's conduct did not constitute market manipulation and the results of the PRARR
into Dynegy was closed. FERC foun
were just and reasonable because the PRA was conducted in accordance with MISO's tariff. With the issuance of the order, this
matter has been resolved in Dynegy's favor. The request for rehearing was denied by FERC in March 2020. The order was
appealed by Public Citizen, Inc. to the D.C. Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing
ng denying Public Citizen,
Company intervened in the case in June 2020. In August 2021, the D.C. Circuit Court issued a ruli
ed to meet its obligation to ensure just and reasonable rates because it did not review the prices
Inc.'s arguments that FERC fail
resulting from the auction before those prices went into effecff
ious in failing to
t and that FERC was arbit
adequately explain its decision to close its investigation into whether Dynegy engaged in market manipulation. The D.C.
Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part finding that FERC's decision that the auction results were
just and reasonable solely because the auction process complied with the filed tariff was unreasoned and remanded the case
back to FERC forff
, 2022 the Illinois Attorney General and Public Citizen, Inc.
filed a motion at FERC requesting that FERC on remand reverse its prior decision and either find that auction results were not
just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and
discovery. We intend to vigorously defend our position, including by filing a response to the motion.

further proceedings on that issue. On February 4rr

rary and capric

a

ff

rr

r

Other MatteMM rs

We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the
on our results of

ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect
operations, liquidity or finaff

ncial condition.

ff

Labor Contracts

We employ certain personnel who are represented by labor

unions, the terms of whose employment are governed by
a
collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel
engaged in lignite mining operations, lignite-, coal-, natural gas- and nuclear-fueled generation operations, as well as some
battery operations, expire on various dates between March 2022 and May 2024, but remain effective 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 our existing agreements to have a material adverse effect on our results of operations, liquidity or finaff

ncial condition.

a

135

Nuclear Insurance

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

With regard to nuclear liabia lity coverage, the Act provides forff
rr

financial protection for the public in the event of a
significant nuclear generation plant incident. The Act sets the statutory l
imit of public liabia lity for a single nuclear incident at
$13.5 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S.
Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $13.5 billion limit forff
a
ility resulting in public
single incident. As required, we insure against a possible nuclear incident at our Comanche Peak facff
nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide
retrospective payment plan known as Secondary Financial Protection (SFP).

Under the SFP, in the event of any single nuclear liabia lity loss in excess of $450 million at any nuclear generation facility
in the U.S., each operating licensed reactor in the U.S. 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 by November 2023. Assessments are currently limited to $20.5 million per operating licensed
reactor per year per incident. As of December 31, 2021, our maximum potential assessment under the industry retrospective
each incident. The
plan would be approximately $275 million per incident but no more than $41 million in any one year forff
ility.
potential assessment is triggered by a nuclear liability loss in excess of $450 million per accident at any nuclear facff

The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain
ization insurance, and requires that the
at least $1.06 billion of nuclear accident decontamination and reactor damage stabila
condition, to decontaminate a plant pursuant to a plan submitted to,
proceeds thereof be used to place a plant in a safe aff
the NRC prior to using the proceeds for plant repair or restoration, or to provide for prematuret
and approved by,
decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance forff
our
Comanche Peak facility in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0
billion (subject to a $5 million deductible per accident except forff
hazards which are subject to a $9.5 million deductible
per accident), above which we are self-insured.

nd stablea

t
natural

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 forff more than twelve weeks as a
result of covered direct physical damage. Such coverage provides forff 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.

136

14. EQUITY

Common Stoctt k Issuanc

II

es and Repurchases

Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2021, 2020

and 2019 are refleff cted in the tablea

below.

Balance at December 31, 2018

Shares issued (a) (b)

Shares retired

Shares repurchased

Balance at December 31, 2019

Shares issued (a)

Shares retired

Balance at December 31, 2020

Shares issued (a)
Shares retired

Shares repurchased (c)

Balance at December 31, 2021

Shares
Issued

Treasury
Shares

Shares
Outstanding

526,031,092

(32,815,783)

493,215,309

2,716,349

18,773,958

21,490,307

(6,106)

—

(6,106)

— (27,001,399)

(27,001,399)

528,741,335

(41,043,224)

487,698,111

1,611,462

(3,685)

—

—

1,611,462

(3,685)

530,349,112

(41,043,224)

489,305,888

2,583,761

—

2,583,761

(3,397)

—
— (27,988,518)

(3,397)
(27,988,518)

532,929,476

(69,031,742)

463,897,734

____________
(a) Shares issued includes share awards granted to nonemployee directors.
(b) The year ended December 31, 2019 includes 18,773,958 treasury shares issued in connection with the settlement of all

outstanding TEUs as discussed below.

(c) Shares repurchased in the year ended December 31, 2021 include 5,174,863 of unsettled shares as of December 31, 2021.

Share Repurchase Programs

In October 2021, we announced that the Board has authorized a new share repurchase program (Share Repurchase
Program) under which up to $2.0 billion of our outstanding shares of common stock may be repurchased. The Share
Repurchase Program became effective on October 11, 2021, at which time it superseded the 2020 Share Repurchase Program
(described below) and any authorization remaining as of such date. We intend to use the net proceeds from the Offering
(described below) to repurchase shares of our outstanding common stock.
In the three months ended December 31, 2021,
19,330,365 shares of our common stock were repurchased under the Share Repurchase Program for approximately $409 million
at an average price of $21.16 per share of common stock. As of December 31, 2021, approximately $1.591 billion was
available forff
additional repurchases under the Share Repurchase Program. From January 1, 2022 through February 22, 2022,
16,059,290 of our common stock had been repurchased under the Share Repurchase Program for $355 million at an average
repurchase under the
ry 2rr
price per share of common stock of $22.07, and at Februarr
Share Repurchase Program. We expect to complete repurchases under the Share Repurchase Program by the end of 2022.

2, 2022, $1.236 billion was available forff

Under the Share Repurchase Program, 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 Exchange
eral securities laws. The actual timing, number and value of shares repurchased
Act, or by other means in accordance with fedff
under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of facff
tors,
including our capita
al allocation priorities, the market price of our stock, general market and economic conditions, applicable
legal requirements and complim ance with the terms of our debt agreements.

In September 2020, we announced that the Board authorized a share repurchase program (2020 Share Repurchase
Program) under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The 2020 Share
Repurchase Program was effective January 1, 2021, at which time the 2018 Share Repurchase Plan (described below) and all
authorized amounts remaining thereunder terminated as of such date. In the year ended December 31, 2021, 8,658,153 shares
of our common stock were repurchased under the 2020 Share Repurchase Program for approximately $175 million at an
average price of $20.21 per share of common stock. The 2020 Share Repurchase Program was superseded by the Share
Repurchase Program in October 2021.

137

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 purchased, and this authorized amount was full
y utilized in 2018. In November 2018,
we announced that the Board had authorized an incremental share repurchase program under which up to $1.250 billion of our
outstanding stock may be purchased, resulting in an aggregate $1.750 billion share repurchase program (collectively, 2018
Share Repurchase Program). In the year ended December 31, 2019, 26,322,166 shares of our common stock were repurchased
under the 2018 Share Repurchase Program for approximately $640 million (including related fees and expenses) at an average
price of $24.34 per share. There were no repurchases under the 2018 Share Repurchase Program in the year ended December
31, 2020. The 2018 Share Repurchase Program was terminated on January 1, 2021.

ff

Preferred Stock

SS

On October 15, 2021 (Series A Issuance Date), we issued of 1,000,000 shares of Series A Preferred Stock in a private
offering (Series A Offering). The net proceeds of the Series A Offering were approximately $990 million, after deducting
underwriting commissions and offering expenses. We intend to use the net proceeds from the Series A Offering to repurchase
shares of our outstanding common stock under the Share Repurchase Program (described above).

On December 10, 2021 (Series B Issuance Date), we issued of 1,000,000 shares of Series B Preferred Stock in a private
offering (Series B Offering). The net proceeds of the Series B Offering were approximately $985 million, after deducting
underwriting commissions and offering expenses. We intend to use the net proceeds from the Series B Offering to pay for or
reimburse existing and new eligible renewable and battery ESS developments.

The Series A Preferred Stock and the Series B Preferred Stock are not convertible into or exchangeable forff

any other
securities of the Company and have limited voting rights. The Series A Preferred Stock may be redeemed at the option of the
Company at any time after the Series A First Reset Date (definff ed below) and in certain other circumstances prior to the Series
A First Reset Date. The Series B Preferred Stock may be redeemed at the option of the Company at any time after the Series B
First Reset Date (defined below) and in certain other circumstances prior to the Series B First Reset Date.

ii
Dividends

Common Stock — In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the
first quarter of 2019. Each dividend under the program is 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,
Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual

limitations.

t

In February 2019, May 2019, July 2019 and October 2019, the Board declared quarterly dividends of $0.125 per share

that were paid in March 2019, June 2019, September 2019 and December 2019, respectively.

In February 2020, April 2020, July 2020 and October 2020, the Board declared quarterly dividends of $0.135 per share

that were paid in March 2020, June 2020, September 2020 and December 2020, respectively.

In February 2021, April 2021, July 2021 and October 2021, the Board declared quarterly dividends of $0.15 per share that

were paid in March 2021, June 2021, September 2021 and December 2021, respectively.

In February 2022, the Board declared a quarterly dividend of $0.17 per share that will be paid in March 2022.

d StocS

ff
Preferre

k — The annual dividend rate on each share of Series A Preferred Stock is 8.0% from the Series A Issuance
Date to, but excluding October 15, 2026 (Series A First Reset Date). On and after the Series A First Reset Date, the dividend
rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend
determination date (subject to a floor
of 1.07%), plus a spread of 6.93% per annum. The Series A Preferred Stock has a
liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series A
Preferred Stock are payablea
semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when,
as and if declared by the Board.

ff

In February 2022, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferredr

Stock that will be

paid in April 2022.

138

The annual dividend rate on each share of Series B Preferred Stock is 7.0% from the Series B Issuance Date to, but
excluding December 15, 2026 (Series B First Reset Date). On and after the Series B First Reset Date, the dividend rate on each
share of Series B Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination
of 1.26%), plus a spread of 5.74% per annum. The Series B Preferred Stock has a liquidation preference
date (subject to a floor
of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series B Preferred Stock are
payablea
semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared
by the Board.

ff

ii
Dividend

Restrictions

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, 2021, Vistra Operations can
distribute approximately $7.3 billion to Parent under the Credit Facilities Agreement without the consent of any party. The
amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations
to Parent of approximately $405 million, $1.1 billion and $3.9 billion during the years ended December 31, 2021, 2020 and
2019, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make
any payments required under the TRA oRR
r the Tax Matters Agreement or, to the extent arising out of Parent's ownership or
operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31,
2021, all of the restricted net assets of Vistra Operations may be distributed to Parent.

In addition to the restrictions under the Credit Facilities Agreement, under applicable Delaware law, we are only permitted
al (the aggregate
the fiscal year in which the distribution is declared or

to make distributions either out of "surplus," which is defined as the excess of our net assets above our capita
par value of all outstanding shares of our stock), or out of net profits forff
the prior fiscal year.

Under the terms of the Series A Preferred Stock and the Series B Preferred Stock, unless full cumulative dividends have
been or contemporaneously are being paid or declared and a sum sufficient for the payment thereof set apart for payment on all
outstanding Series A Preferred Stock (and any parity securities) and Series B Preferred Stock (and any parity securities),
respectively, with respect to dividends through the most recent dividend payment dates, (i) no dividend may be declared or paid
or set apart for payment on any junior security (other than a dividend payablea
solely in junior securities with respect to both
dividends and the liquidation, winding-up and dissolution of our affairs), including our common stock, and (ii) we may not
redeem, purchase or otherwise acquire any parity security or junior security, including our common stock, in each case subject
Stock and the Series B Preferred
to certain exceptions as described in the certificate of designation of the Series A Preferredr
Stock, respectively.

Accumulatell

d Other ComCC prehm

ensive Income

During the years ended December 31, 2021, 2020 and 2019, we recorded changes in the funded statust

of our pension and
other postretirement employee benefit liability totaling $(24) million, $23 million and $11 million, respectively. During the
years ended December 31, 2021, 2020 and 2019, $(8) million, $(5) million and $(3) million respectively was reclassified fromff
accumulated other comprehensive income and reported in other deductions.

Warrantstt

At the Merger Date, the Company entered into an agreement whereby the holder of each outstanding warrant previously
issued by Dynegy would be entitled to receive, upon paying an exercise, price of $35.00 (subject to adjustment from time to
time), the number of shares of Vistra common stock that such holder would have been entitled to receive if it had held one share
of Dynegy common stock at the closing of the Merger, or 0.652 shares of Vistra common stock. Accordingly, upon exercise, a
warrant holder would effectively pay $53.68 (subject to adjustment of the exercise price fromff
time to time) per share of Vistra
agreement, the exercise price of each
common stock received.
warrant was adjusted downward to $34.54 (subject to furthe
r adjustment from time to time), or $52.98 (subject to adjustment of
the exercise price fromff
time to time) per share of Vistra common stock received. As of December 31, 2021, nine million
warrants expiring in 2024 were outstanding. The warrants were included in equity based on their fair value at the Merger Date.

In July 2021, in accordance with the terms of the warrant

r

ff

139

)s
Tangible Equityii Units (TEUs

TT

At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00% TEUs, each with a stated
amount of $100.00 and each comprised of (i) a prepaid stock purchase contract that delivered to the holder on July 1, 2019,
4.0813 shares of Vistra common stock per contract with cash paid in lieu of any fractional shares at a rate of $22.5954 per share
and (ii) a senior amortizing note with an outstanding principal amount of $38 million at the Merger Date that paid an equal
quarterly cash installment of $1.75 per amortizing note (see Note 11). In the aggregate, the annual quarterly cash installments
were equivalent to a 7.00% cash payment per year with respect to each $100.00 stated amount of TEUs. The amortizing notes
were accounted forff
as debt while the stock purchase contract was included in equity based on the fair value of the contract at the
Merger Date (see note 11). The entire class of TEUs were suspended from trading on the New York Stock Exchange on July 1,
2019 and removed from listing and registration on July 12, 2019. On July 1, 2019, approximately 18.8 million treasury shares
of Vistra common stock were issued in connection with the settlement of all outstanding TEUs.

15. 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 comparablea
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 majoa rity 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 Chief
Financial Officer.

Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance
risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the
credit risks associated with our credit standing and the credit standing of our counterparties (see Note 16 for additional
information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate fact
ors in
calculating these fair value measurement adjustmd

ents.

ff

We categorize our assets and liabilities recorded at faiff

r value based upon the following fair value hierarchy:

•

•

•

Level 1 valuations use quoted prices in active markets forff
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
ff
certain margin amounts related to changes in fair value on certain CME transactions that 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
observablea
. 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 facff

tors.

inputs for the asset or liabia lity. Unobservablea

inputs are used to the extent
Level 3 valuations use unobservablea
inputs are not available, thereby allowing for situations in which there is little, if any, market activity for
observablea
the market
the asset or liabia lity at the measurement date. We use the most meaningful information available fromff
r value. Significant
combined with internally developed valuation methodologies to develop our best estimate of faiff
unobservablea
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 tablea

s, 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.

140

Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet

December 31, 2021

December 31, 2020

Level
1

Level
2

Level
3 (a)

Reclass
(b)

Total

Level
1

Level
2

Level
3 (a)

Reclass
(b)

Total

dates shown below:

Assets:

Commodity contracts
Interest rate swapsa
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:

$ 1,408
—

$ 889
19

$ 442
—

$

724

—

—

—
$ 2,132

679
$ 1,587

—
$ 442

$

5
—

—

—
5

$ 2,744
19

$ 452 $ 201 $ 205
—

—

72

724

623

—

—

—

—
$ 1,075 $ 891 $ 205

618

679
4,166

557
$ 4,723

$

$

$

$

76
—

—

—
76

$ 934
72

623

618
2,247

433
$ 2,680

76
—
76

$ 1,009
404
$ 1,413

Commodity contracts
Interest rate swapa s
Total liabilities

$ 2,153
—
$ 2,153

$ 650
217
$ 867

$ 802
—
$ 802

$

$

5
—
5

$ 3,610
217
$ 3,827

$ 578 $ 172 $ 183
—
$ 578 $ 576 $ 183

404

—

____________
(a) See table below for description of Level 3 assets and liabilities.
(b) Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or

vice versa, as presented in our consolidated balance sheets.

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

See Note 21.

(d) The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the
amounts presented in our consolidated balance sheets. Certain investments measured at fair value using the net asset
value per share (or its equivalent) have not been classified in the fair value hierarchy.

Commodity contracts consist primarily of natural

gas, electricity, coal and emissions agreements and include financial
instruments entered into forff
economic hedging purposes as well as physical contracts that have not been designated as normal
purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest
to fixed rates. See Note 16 forff

further discussion regarding derivative instruments.

t

Nuclear decommissioning trust assets represent securities held forff

decommissioning of our nuclear generation facility. These investments include equity, debt and other fixeff
consistent with investment rules established by the NRC and the PUCT.

the purpose of funding the future retirement and
d-income securities

141

The folff

lowing tables present the fair value of the Level 3 assets and liabilities by majora

contract type and the significant

unobservable inputs used in the valuations at December 31, 2021 and 2020:

Fair Value

December 31, 2021

Significant Unobservable Input
Hourly price curve shapea
(c)

Range (b)
$ — to $ 60

MWh

Average
(b)
$ 30

Illiquid delivery periods for
hub power prices and heat
rates (d)

$ 20

to $140

$ 80

MWh

)
Gas to power correlation (e

0 % to
1

100 % 56 %

)
Power and gas volatility (e

5

o
t%

4

90 % 248 %

Illiquid price differe
nces
between settlement points
(g)

ff

$(30)

to $ 10

$ (9)

MWh

Gas basis (h)

$ (1)

to $ 16

$ 8

MMBtu

—

61

Income
Approach

Probability of default (i)
Recovery rate (j)

— % to
— % to

40 % 20%
40 % 20%

Contract Type (a)
Electricity
purchases and sales

Assets

Liabilities

Total

$

204 $

(470) $

(266)

Valuation
Technique
Income
Approach

Options

1

(209)

(208) Option
Pricing
Model

Financial
transmission rights

122

(34)

88 Market

(86)

(57)

Approach
(f)

Income
AApproa hch

29

61

Natural gas

Coal

Other (k)

Total $

25
442 $

(3)
(802) $

22
(360)

Fair Value

December 31, 2020

Contract Type (a)
Electricity
purchases and sales

Assets

Liabilities

Total

$

61 $

(90) $

(29)

Valuation
Technique
Income
Approach

Options

Financial
transmission rights

Natural gas

Coal

Other (k)

38

92

7

1

6

(56)

(18) Option
Pricing
Model

(16)

76 Market

14)
(

(5)

(2)

Approach
(f)

Income
AApproa hch

Income
Approach

(7)

(4)

4

22

Total $

205 $

(183) $

Significant Unobservable Input
Hourly price curve shapea
(c)

Range (b)
$ — to $ 85

MWh

Average
(b)
$ 43

Illiquid delivery periods for
hub power prices and heat
rates (d)

$ 25

to $125

$ 75

MWh

)
Gas to power correlation (e

0 % to
3

100 % 64 %

)
Power and gas volatility (e

5

o
t%

6

65 % 336 %

Illiquid price differe
nces
between settlement points
(g)

ff

$ (5)

to $ 50

$ 22

MWh

Gas basis (h)

$ (1)

to $ — $ —

Probability of default (i)
Recovery rate (j)((

— % to
— % to

40 % 20%
40 % 20%

MMBtu

____________
(a) Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and
MISO regions. The forward purchase contracts (swapsa
and options) used to hedge electricity price differences between
settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs)
ons
in PJM, ISO-NE, NYISO and MISO regions. Options consist of physical electricity options, spread options, swaptia
and natural gas options.

(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The
average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional
amount.

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

142

(d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT heat rate variability.
(e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM.
(f) While we use the market approach, there is insufficff
(g) Primarily based on the historical price differe
(h) Primarily based on the historical forward PJM and Northeast gas basis prices.
(i) Estimate of the range of probabilities of default based on past experience, the length of the contract, and both the

nces between settlement points within ERCOT hubs and load zones.

ient market data to consider the valuation liquid.

ff

Company's and the counterparty's credit ratings.

(j) Estimate of the default recovery rate based on historical corporate rates.
(k) Other includes contracts for environmental allowances.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2021,
the years ended December 31,

discussion of transfers between Level 2 and Level 3 forff

below forff

2020 and 2019. See the tablea
2021, 2020 and 2019.

The following tablea
31, 2021, 2020 and 2019.

presents the changes in faiff

r value of the Level 3 assets and liabilities for the years ended December

Net asset (liability) balance at beginning of period

Total unrealized valuation gains (losses) (a)
Purchases, issuances and settlements (b):

Purchases
Issuances
Settlements

Transfers into Level 3 (c)
Transfers out of Level 3 (c)

Net change (d)

Net asset (liability) balance at end of period
Unrealized valuation gains (losses) relating to instruments held at end of
period

Year Ended December 31,

2021

2020

2019

$

$

$

22 $
(53)

114
(36)
(314)
(2)
(91)
(382)
(360) $

(74) $
(5)

164
(28)
(90)
(2)
57
96
22 $

(364) $

18 $

(135)
8

176
(81)
(64)
10
12
61
(74)

(61)

____________
(a) During the year ended December 31, 2021,

loss of $341 million due to the third quarter 2021
discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is
no longer considered probablea

throughout the contract term.

includes a net

(b) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and

(c)

t option premiums paid or received, including CRRs and FTRs.

issuances reflecff
Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods
presented are in and out of Level 2. For the year ended December 31, 2021, transfers into Level 3 primarily consist of
gas, emissions and coal derivatives where forward pricing inputs have become unobservable and transfers out of
t
natural
Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the
year ended December 31, 2020, transfers out of Level 3 primarily consist of natural
gas, power and coal derivatives where
forward pricing inputs have become observable. For the year ended December 31, 2019, transfers out of Level 3
.
primarily consist of power and coal derivatives where forward pricing inputs have become observablea

t

(d) Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity
contracts (excluding the net liabilities assumed in connection with the Merger) are reported as operating revenues in our
consolidated statements of operations.

16. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

tt
Strategi

c UseUU of Derivativtt es

We transact in derivative instruments, such as options, swaps,a

futures and forward contracts, to manage commodity price

and interest rate risk. See Note 15 for a discussion of the fair value of derivatives.

143

dd
edHH ging

Commodity Htt

and Trading Activityii — We utilize natural

gas and electricity derivatives to reduce exposure to
our generation assets and to hedge
changes in electricity prices primarily to hedge future revenues from electricity sales fromff
future purchased power costs for our retail operations. We also utilize short-term electricity, natural
gas, coal and emissions
derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies,
financial instituti
ons, electric utilities, independent power producers, fuel 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 consolidated statements of operations
in operating revenues and fuel, purchased power costs and delivery fees.

t

t

t

tt
Interes

t 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
are
losses arising from changes in the fair value of the swapsa
reported in our consolidated statements of operations in interest expense and related charges. During 2019, Vistra entered into
$2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixeff
d rate. The terms of
these new swaps were matched against the terms of certain existing swaps,a
effectively offsetting the hedge of the existing swaps
These matched swapsa will settle over time, in accordance with the
and fixing the out-of-the-money position of such swaps.a
original contractual
continue to hedge our exposure on $2.30 billion of debt through July
terms. The remaining existing swapsa
2026.

as well as realized gains and losses uponu

settlement of the swapsa

t

Financial Statement Effeff cts ott

f Do

erivatives

t

t

Substantially all derivative contractual

assets and liabilities are accounted for under mark-to-market accounting consistent
s provide detail of
with accounting standards related to derivative instruments and hedging activities. The following tablea
derivative contractual
assets and liabilities as reported in our consolidated balance sheets at December 31, 2021 and 2020.
Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross
value of the contract. During the year ended December 31, 2021, a net loss of $298 million was recognized in operating
revenues due to the third quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract
portfolio where physical settlement is no longer considered probable throughout the contract term. These amounts are reflected
in commodity contracts derivative liabilities at December 31, 2021.

Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Net assets (liabila

ities)

Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Net assets (liabila

ities)

December 31, 2021

Derivative Assets

Derivative Liabilities

Commodity
Contracts

Interest Rate
Swaps

Commodity
Contracts

Interest Rate
Swaps

Total

$

$

$

$

2,496
244
—
(1)
2,739

$

$

14
5
—
—
19

$

$

$

3
1
(2,964)
(645)
(3,605) $

December 31, 2020

— $
—
(59)
(158)
(217) $

2,513
250
(3,023)
(804)
(1,064)

Derivative Assets

Derivative Liabilities

Commodity
Contracts

Interest Rate
Swaps

Commodity
Contracts

Interest Rate
Swaps

Total

665
197
(1)
(3)
858

$

$

19
53
—
—
72

$

$

$

64
8
(717)
(288)
(933) $

— $
—
(71)
(333)
(404) $

748
258
(789)
(624)
(407)

As of December 31, 2021 and 2020, there were no derivative positions accounted forff

as cash flow or fair value hedges.

144

The folff

lowing table presents the pre-tax 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 (consolidated statements of operations presentation)

2021

2020

2019

Commodity contracts (Operating revenues)

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

Interest rate swapsa

(Interest expense and related charges)

Net gain (loss)

$

$

(1,196) $

241

$

732

81

4

(196)

(383) $

49

$

339

(1)

(217)

121

Year Ended December 31,

ll
Balanc

e SheSS et Presentattt

iontt

of Derivatives

tt

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
the right to offset assets and liabilities and collateral in order to reduce
agreements with certain counterparties that allow forff
credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements,
monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract
counterparty.

Generally, margin deposits that contractually offset

these derivative instruments are reported separately in our
consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions
that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from
counterparties are primarily used for working capia tal or other general corporate purposes.

The following tablea

s 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, 2021

December 31, 2020

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 swapsa
Total derivative
assets

Derivative liabilities:

Commodity contracts
Interest rate swapsa
Total derivative
liabilities

$

2,739
19

$

(2,051) $
(19)

(27) $
—

2,758

(2,070)

(27)

(3,605)
(217)

2,051
19

(3,822)

2,070

784
—

784

661
—

661

(770)
(198)

(968)

$

858
72

930

$

(667) $
(72)

(11) $
—

(739)

(11)

(933)
(404)

(1,337)

667
72

739

138
—

138

180
—

180

(128)
(332)

(460)

Net amounts

$ (1,064) $

— $

757

$

(307)

$

(407) $

— $

127

$

(280)

____________
(a) Amounts presented exclude trade accounts receivablea
(b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin

and payable related to settled finaff

ncial instruments.

requirements, and, to a lesser extent, initial margin requirements.

145

Derivative Volumes

The following tabla e presents the gross notional amounts of derivative volumes at December 31, 2021 and 2020:

Derivative type
Natural gas (a)
Electricity
Financial transmission rights (b)
Coal
Fuel oil
Emissions
Renewable energy certificates
Interest rate swapsa
Interest rate swapsa

– variable/fixed (c)
- fixff ed/variable (c)

December 31, 2021

December 31, 2020

Notional Volume
4,701
440,236
224,876
25
87
18
32
6,720
2,120

$
$

Unit of Measure
5,264 Million MMBtu

438,863 GWh
217,350 GWh

20 Million U.S. tons
176 Million gallons
8 Million tons
18 Million certificates
6,720 Million U.S. dollars
2,120 Million U.S. dollars

$
$

____________
(a) Represents gross notional forward sales, purchases and options transactions, locational basis swapsa

and other natural

t

gas

transactions.

(b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between

settlement points within regions.
Includes notional amounts of interest rate swapsa with maturity dates through July 2026.

(c)

Credit Risk-Re-

latedtt Contintt gent FeaFF tures of Derivativtt es

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 formff
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 faiff
lure under other
financing arrangements related to payment terms or other covenants.

The following tablea

presents the commodity derivative liabilities subject to credit risk-related contingent features that are

not fully collateralized:

Fair value of derivative contract liabila
Offsetting fair value under netting arrangements (b)
Cash collateral and letters of credit
Liquidity exposure

ities (a)

December 31,

2021

2020

$

$

(1,200) $
660
95
(445) $

(679)
262
35
(382)

____________
(a) Excludes faiff

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

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

netting arrangements.

Concentrations of Credit Riskii Relatell

d to Dtt

erivatives

We have concentrations of credit risk with the counterparties to our derivative contracts. As of December 31, 2021, total
credit risk exposure to all counterparties related to derivative contracts totaled $3.742 billion (including associated accounts
receivable). The net exposure to those counterparties totaled $1.417 billion at December 31, 2021 after taking into effect
netting arrangements, setoff provisions and collateral, with the largest net exposure to ERCOT totaling $619 million. As of
December 31, 2021, the credit risk exposure to the banking and financial sector represented 54% of the total credit risk
exposure and 4% of the net exposure.

146

Exposure to banking and financial sector counterparties is considered to be within an acceptablea

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 defauff
lt by any of these counterparties would have a material effeff ct 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.

17. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS

Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible
its interests in the
employees of its subsidiaries. Oncor is a participant in the Retirement Plan. As Vistra accounts forff
Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension
benefit information presented below. After amendments in 2012, employees in the Retirement Plan now consist entirely of
participants who were 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.

ff

Vistra 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 forff
ula depending on the retiree's age and years of service.
such coverage vary based on a formff

Effective January 1, 2018, Vistra 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 (or its predecessors) are split between
Oncor and Vistra. As Vistra accounts forff
its interest in this OPEB plan as a multiple employer plan, only Vistra's share of the
plan assets and obligations are reported in the OPEB information presented below. In addition, Vistra is the sponsor of OPEB
plans that certain EFH Corp. and Dynegy retirees participate in.

Pension and OPEB Coststt

Pension costs
OPEB costs

Total benefit costs recognized as expense

Market-Relatell

d ValVV ue of Assets Held in Pension Benefite Trusts

Year Ended December 31,

2021

2020

2019

$

$

6
8
14

$

$

11
7
18

$

$

9
11
20

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 forff
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.

147

Detaileii d Inform

II

ation Regarding Pension Plans

ll

and OPEBPP

Benefite stt

The following information is based on a December 31, 2021, 2020 and 2019 measurement dates:

Assumptions Used to Determine Net Periodic Pension and
Benefitff Cost:

Discount rate
Expected rate of compensation increase
Interest crediting rate for cash balance
Expected return on plan assets (Vistra Plan)
Expected return on plan assets (Dynegy Plan)
Expected return on plan assets (EEI Plan)
Expected return on plan assets (EEI Union)
Expected return on plan assets (EEI Salaried)
m
s ott
Service cost
Interest cost
Expected returnt
Amortization of unrecognized amounts
Immediate pension and postretirement benefit cost

etNN Pension and Benefie t Cost:CC

on assets

f No

Component

Net periodic pension and OPEB cost
in Plan Assets att

nd Benefitff Obligati

i

ons

in Other Compre

CC

hensive Income:

Other Changes
CC
Recognizedii

Retirement Plan

OPEB Plans

Year Ended December 31,

Year Ended December 31,

2021

2020

2019

2021

2020

2019

2.50 % 3.24 % 4.37 %
3.41 % 3.29 % 3.35 %
3.00 % 3.50 % 3.50 %
3.77 % 4.44 % 4.80 %
4.42 % 5.28 % 5.31 %
4.72 % 5.45 % 5.56 %

2.51 % 3.25 % 4.35 %

6.79 % 7.07 % 5.36 %
2.95 % 3.43 % 4.70 %

$

$

5
16
(18)
3
—
6

$

6
20
(23)
1
7
$ 11

$

$

7
25
(26)
—
3
9

$

$

1
4
(2)
5
—
8

$

$

$

2
4
(2)
4
(1)
7

$

2
6
(1)
3
1
$ 11

5

$ —

Net (gain) loss and prior service (credit) cost

$ (29)

$ 17

$ 11

$ (12)

Total recognized in net periodic benefit cost and other
comprehensive income

Assumptions Used to Determine Benefie t Obligations at Period
End:

$ (23)

$ 28

$ 20

$

(4)

$ 12

$ 11

Discount rate
Expected rate of compensation increase
Interest crediting rate for cash balance plans

2.84 % 2.50 % 3.24 %
3.49 % 3.41 % 3.29 %
3.00 % 3.00 % 3.50 %

2.87 % 2.51 % 3.25 %

Net Actuarial Gainsii

(Losses)

to increasing discount rates due to changes in the corporate bond markets and gains attributablea

Retirement Plan — For the year ended December 31, 2021, the net actuarial gain of $24 million was driven by gains
to actual asset
to demographic assumptim on updates to reflect recent
rial assumptim on updates to reflect current market conditions, plan amendments, settlements and plan

attributablea
performance exceeding expectations, partially offset by losses attributablea
plan experience, actuat
experience different than expected.

to
For the year ended December 31, 2020, the net actuarial loss of $29 million was driven by losses attributablea
decreasing discount rates due to changes in the corporate bond markets, actuarial assumptim on updates to reflect current market
conditions and plan amendments, partially offset by gains attributablea
to actual asset performance exceeding expectations, life
expectancy updat

es, annuity purchases, lump sum windows and plan experience different than expected.

u

to
For the year ended December 31, 2019, the net actuarial loss of $16 million was driven by losses attributablea
decreasing discount rates due to changes in the corporate bond markets, actuarial assumptim on updates to reflect current market
than expected, partially offset by gains
conditions, annuity purchases, plan amendments and plan experience different
attributablea

to actual asset performance exceeding expectations and life expectancy updates.

ff

148

Plans — For the year ended December 31, 2021, the net actuarial gain of $7 million was driven by gains
OPEBPP
attributablea
than expected,
to increasing discount rates due to changes in the corporate bond markets, plan experience different
updates to health care claims and trend assumptim ons and actual asset performance exceeding expectations, partially offset by
losses attributable to demographic assumption updates and life expectancy updat

es.

u

ff

For the year ended December 31, 2020, the net actuarial loss of $10 million was driven by losses attributablea

decreasing discount rates due to changes in the corporate bond markets and plan experience different
to actual asset performance exceeding expectations, life expectancy updat
offset by gains attributablea
care claims and trend assumptim ons.

ff
u

to
than expected, partially
es and updates to health

For the period ended December 31, 2019, the net actuarial loss of $5 million was driven by losses attributablea

decreasing discount rates due to changes in the corporate bond markets and plan experience different
offset by gains attributablea
related assumptions and changes due to the repeal of certain Affordable Care Act fees.

to
than expected, partially
to actual asset performance exceeding expectations, life expectancy changes, updates to health care

ff

Change in Pension and Postretirement Benefie t Obligations:
Projected benefit obligation at beginning of period

Service cost
Interest cost
Participant contributions
Lump-sum window
Annuity purchase
Actuarial 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

Employer contributions
Participant contributions
Lump-sum window
Annuity purchase
t
Actual
Benefits paid

gain on assets

Fair value of assets at end of year
Funded StatSS
Projected pension benefit obligation
Fair value of assets

us:

Funded status at end of year

Amounts Rtt

ecognizedii

in the Balance

l

CC
Sheet Consis

t of:o

Other noncurrent assets
Other current liabilities
Other noncurrent liabilities
Net liability recognized
ecognizedii

Amounts Rtt
Income Consist of:
Net loss and prior service cost

in Accumulated Other Compre

CC

hensive

Retirement Plan

OPEB Plans

Year Ended December 31,

Year Ended December 31,

2021

2020

2021

2020

643 $
5
16
—
—
—
(11)
(48)
605 $
600 $

485 $
1
—
—
—
30
(46)
470 $

(605) $
470
(135) $

— $
—
(135)
(135) $

674
6
20
—
(6)
(29)
46
(68)
643
639

528
16
—
(6)
(29)
40
(64)
485

(643)
485
(158)

$

$
$

$

$

$

$

— $
—
(158)
(158)

$

157 $
1
4
3
—
—
(6)
(13)
146 $
— $

37 $
9
3
—
—
3
(13)
39 $

(146) $
39
(107) $

26 $
(9)
(124)
(107) $

151
2
4
3
—
—
12
(15)
157
—

34
9
3
—
—
4
(13)
37

(157)
37
(120)

23
(9)
(134)
(120)

(13) $

(42)

$

8 $

20

$

$
$

$

$

$

$

$

$

$

149

Fair Value MeaMM surement of Pension and OPEBPP

Planll Assets

Retirement Plan — As of December 31, 2021 and 2020, all of the Retirement Plan assets were measured at fair value

using the net asset value per share (or its equivalent) and consisted of the folff

lowing:

Asset Category:

rr

Cash commingled trusts
Equity securities:
Global equities

Fixed income securities:
Corporate bonds (a)
Government bonds
Other (b)
Real estate

Total assets measured at net asset value

$

December 31,

2021

2020

11

149

199
31
30
50

470

$

11

153

207
37
32
45

485

___________
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.
(b) Consists primarily of high-yield bonds, emerging market debt and bank loans.

OPEB Plans

l — As of December 31, 2021 and 2020, the Vistra OPEB plan assets measured at fair value on a recurring
basis totaled $39 million and $37 million, respectively. At December 31, 2021, assets consisted of $37 million of comingled
classifieff d as Level 1. At
funds valued at net asset value and $2 million of municipal bond and cash equivalent mutual funds
December 31, 2020, assets consisted of $29 million of U.S. equities classifieff d as Level 1 and $8 million of U.S. Treasuries and
municipal bonds classified as Level 2.

ff

Pension Plans with Ptt

rojPP ected Benefit Oii

i
bligati

ons (PBO) and Accumulatell

d Benefit Oii

i
bligati

ons (ABO)O

The following tablea

provides information regarding pension plans with PBO and ABO in excess of the fair value of plan

assets.

Pension Plans with PBO and ABO in Excess Of Plan Assets:tt
Projected benefit obligations

Accumulated benefit obligation

Plan assets

December 31,

2021

2020

$

$

$

605

600

470

$

$

$

643

639

485

Retireii ment Planll

tt
Investmen

t Strate

SS

gye

tt
and Asset Allocat
ions

ll

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit
obligations at an acceptablea
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
by participating in a wide range of investment opportunities.
market instruments. Equity securities are held to enhance returt nsr
International equity securities are used to further diversify the equity portfolio and may include investments in both developed
and emerging markets. Real estate and credit strategies (primarily high yield bonds and emerging market debt) provide
additional portfolio diversification and return potential.

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

ff

s:

Asset Category:
Fixed income

Global equity securities

Real estate

Credit strategies

Target Allocation Ranges

Vistra Plan

65 % - 75%

16 % - 24%

4 % - 8%

3 % - 7%

Dynegy Plan

45 % - 55%

30 % - 38%

8 % - 12%

6 % - 10%

EEI Plan

40 % - 50%

34 % - 42%

10 % - 14%

7 % - 11%

Retirement PlaPP n Expec

EE

ted Long-TerTT m Rrr

ate of Return orr

n Assets Assumptim on

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

current market conditions, rate of inflation, current prospects forff

t

Asset Class:
Fixed income securities

Global equity securities

Real estate

Credit strategies

Weighted average

Retirement Plan

Expected Long-Term Rate of Return

Vistra Plan

Dynegy Plan

EEI Plan

3.1 %

6.9 %

5.4 %

5.5 %

4.2 %

3.1 %

6.9 %

5.4 %

5.5 %

4.8 %

3.1 %

6.9 %

5.4 %

5.5 %

4.9 %

Benefitff Planll Assumed Healthll Care Cost TreTT nd Rates

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

Assumed HeaHH lth Care Cost Trend Rates-Not Medicare Eligibl
Health care cost trend rate assumed forff
Rate to which the cost trend is expected to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate

next year

e:

i

Assumed HeaHH lth Care Cost Trend Rates-Medicare Eligibl
Health care cost trend rate assumed forff
Salaried)
Health care cost trend rate assumed forff
Rate to which the cost trend is expected to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate

next year (Split-Participant Plan)

e:

i

next year (Vistra Plan, EEI Union and EEI

December 31,

2021

2020

6.30 %
4.50 %
2029

9.60 %
8.90 %
4.50 %
2031

6.20 %
4.50 %
2029

9.10 %
8.80 %
4.50 %
2030

Significant Concentrations of Risk

al market conditions and other facff

The plans' investments are exposed to risks such as interest rate, capita
al market and credit risks. We seek to optimize
on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing
returnt
capita
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.

tors specific to us. While we recognize the importance of return,

t

Assumed Discount Rate

We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond
yields and at December 31, 2021 consisted of 307 corporate bonds with an average rating of AA using Moody's, S&P and Fitch
ratings.

s
Contribution
ii

Contributions to the Retirement Plan forff

million and zero, respectively, and no contributions are expected to be made in 2022. OPEB plan funding
December 31, 2021, 2020 and 2019 totaled $9 million and funding

in 2022 is expected to total $9 million.

ff

ff

the years ended December 31, 2021, 2020 and 2019 totaled $1 million, $16
for each year ended

151

Future Benefitff Paymen

a

ts

Estimated future benefitff payments to beneficiaries are as foll

ff

ows:

Pension benefits
OPEB

2022

2023

2024

2025

2026

2027-2031

$
$

67
10

$
$

42
10

$
$

33
10

$
$

34
9

$
$

46
9

$
$

162
39

Qualifi

PP
ll ed Savings Pgg

lans

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 fromff
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 formula in the Retirement Plan) 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 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 $34 million, $34 million and $27 million for the

years ended December 31, 2021, 2020 and 2019, respectively.

152

18. STOCK-BASED COMPENSATION

VistVV ratt

2016 Omnibus Incentive Planll

On the Effective Date, the Vistra 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 forff
issuance as equity-based awards
to our non-employee directors, employees, and certain other persons. Following approval of the Board and approval by the
stockholders at the 2019 annual meeting of the Company, the 2016 Incentive Plan was amended to increase the maximum
number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000. 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) establia
sh the terms and conditions of awards, including the price (if any) to
the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock
be paid forff
options, RSUs, restricted stock, performance awards and other forms
of awards granted or denominated in shares of Vistra
common stock, as well as certain cash-based awards.

ff

If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled forff
any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised
award shall again be available forff
awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards
or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited
for any reason, the number of forfei
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. No awards
under the 2016 Incentive Plan have been settled in cash since the Effective Date.

ted shares shall again be available forff

ff

As is customary in incentive plans of this nature,

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 t

each share limit and the number and kind of shares availablea

o the Vistra stockholders.

t

t

Stock-Based Compensationtt

Expense

xx

Stock-based compensat

m

ion expense is reported as SG&A in the consolidated statements of operations as follows:

Total stock-based compensation expense
Income tax benefit
Stock based-compensation expense, net of tax

OO
Stock Options

Year Ended December 31,

2021

2020

2019

$

$

51
(12)
39

$

$

63
(15)
48

$

$

47
(9)
38

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 Simplifiedff 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 over a period consistent with the expected life aff
ssumption ending on the grant date. We assumed no dividend yield in
the valuation of the options granted from 2016 through 2018, and assumed 2.3% and 1.9% dividend yields in the valuation of
options granted in 2020 and 2019, respectively. These options may be exercised over either three- or four-year graded vesting
periods and will expire 10 years from the grant date.

153

Stock options outstanding at December 31, 2021 are all held by current or former employees. The following tablea

summarizes our stock option activity:

Total outstanding at beginning of period
Granted
Exercised
Forfeited or expired
Total outstanding at end of period

Exercisablea

at December 31, 2021

Year Ended December 31, 2021

Stock Options
(in thousands)
16,030

Weighted
Average
Exercise Price
19.58
$
—
— $
14.25
(894) $
28.18
(1,189) $
19.28
$
13,947

7,234

$

17.60

Weighted Average
Remaining Contractual
Term (Years)
6.7

5.9

5.7

Aggregate
Intrinsic Value
(in millions)

$

$

$

30.8

55.7

42.1

As of December 31, 2021, $12 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 1 year.

Restricted StocSS

k UnitsUU

The following tablea

summarizes our restricted stock unit activity:

Total nonvested at beginning of period
Granted
Vested
Forfeited
Total nonvested at end of period

Year Ended December 31, 2021

Weighted
Restricted Stock
Average Grant
Units
Date Fair Value
(in thousands)
22.35
$
2,252
22.61
1,858
$
22.02
(1,082) $
23.20
(217) $
22.57
$
2,811

of December 31, 2021, $38 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 2 years.

We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis. All PSUs have a
three year performance period and a payout opportunity of 0-200% of target (100%), which is intended to be settled in shares of
Vistra common stock. We recognized compensation expense associated with PSUs of $9 million, $15 million and zero for the
years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021, we have $2 million of unrecognized
compensation cost associated with PSUs.

19. RELATED PARTY TRANSACTIONS

In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received

shares of common stock and TRA RRR

ights in exchange for their claims.

Registr

e

ation Rights

i

Agreement

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the RRARR )
with certain selling stockholders. Pursuant to the RRARR , we maintain a registration statement on Form S-3 providing for
In addition, under the terms of the
registration of the resale of the Vistra common stock held by such selling stockholders.
RRA,RR among other things, 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 RRA the
opportunity to register all or part of their shares on the terms and conditions set forth in the RRA.RR

Tax Receivable Agreement

On the Effective Date, Vistra entered into the TRA wRR

ith a transfer agent on behalf of certain former first-l

ff

ien creditors of

TCEH. See Note 8 forff

discussion of the TRA.RR

154

20. SEGMENT INFORMATION

The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v)
Sunset and (vi) Asset Closure. In the third quarter of 2020, Vistra updat
ed its reportable segments to reflect changes in how the
u
Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates
resources. Management believes the revised reportable segments provide enhanced transparency into the Company's long-term
sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. The
following is a summary of the upda

ted segments:

u

•

•

•

The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT,
PJM and MISO segments. Given recent and expected future retirements of certain power plants, management
believes it is important to have a segment which differenti
ates between operating plants with defined retirement plans
and operating plants without defined retirement plans.
The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S.
electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes
operations in PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively.
The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the
Corporat
e and Other non-segment. As reflected by the Moss Landing and Oakland ESS projects (see Note 3), the
r
Company expects to expand its operations in the West segment.

ff

Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of
our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for
evaluating performance or allocating resources.

The Retail segment is engaged in retail sales of electricity and natural

gas to residential, commercial and industrial
customers. Substantially all of these activities are conducted by TXU Energy, Ambit, Value Based Brands, Dynegy Energy
Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 states in the U.S.

t

The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk
management activities, fuel production and fuel logistics management. The Texas segment represents results fromff
the ERCOT
market and was referred to as the ERCOT segment prior to the third quarter of 2020. The East segment represents results fromff
these markets into one
the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results fromff
reportable segment, East, given similar economic characteristics.

The West segment represents results fromff

the CAISO market, including our development of battery ESS projects at our

Moss Landing and Oakland power plant sites (see Note 3).

The Sunset segment consists of generation plants with announced retirement plans. Separately reporting the Sunset
segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and
West segments. We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset
segment for the generation plants that have announced retirement plans.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 4).
Separately reporting the Asset Closure segment provides management with better information related to the performance and
earnings power of Vistra'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 the
commodity risk management activities to the Asset Closure segment for the generation plants that were retired in 2018, 2019
and 2020.

Corporate

r

and Other represents the remaining non-segment operations consisting primarily of general corporate expenses,

interest, taxes and other expenses related to our support functions that provide shared services to our operating segments.

The accounting policies of the business segments are the same as those described in the summary of significff ant
accounting policies in Note 1. Our CODM uses more than one measure to assess segment performance, including segment net
income (loss), which is the measure most comparablea
to consolidated net income (loss) prepared based on U.S. 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.

155

For the year ended

Retail

Texas

East

West

Sunset

Asset
Closure

Corporate

and Other (b) Eliminations Consolidated

Operating revenues (a):
December 31, 2021
December 31, 2020
December 31, 2019

Depreciation and
amortization:

December 31, 2021
December 31, 2020
December 31, 2019

Operating income
(loss):

$ 7,871
8,270
6,872

$ 2,790
4,116
3,836

$ 2,587
2,415
2,790

$

374
282
338

$ 739
1,252
1,602

$ — $
3
341

— $
—
—

(2,284) $
(4,895)
(3,970)

12,077
11,443
11,809

$ (212) $ (608) $ (698) $
(475)
(472)

(721)
(680)

(303)
(292)

(60) $ (139) $ — $
(19)
(19)

(133)
(120)

(22)
—

(36) $
(64)
(57)

— $
—
—

(1,753)
(1,737)
(1,640)

December 31, 2021
December 31, 2020
December 31, 2019

$ 2,213
312
155

$(2,601) $ (552) $

1,761
1,314

73
398

(8) $ (428) $
39
88

(420)
271

(56) $
(109)
(107)

(83) $
(137)
(127)

— $
—
1

(1,515)
1,519
1,993

$

1
3
3

— $
—
—

(384)
(630)
(797)

458
(266)
(290)

— $
—
1

(1,264)
624
926

$

$

Interest expense and
related charges:

December 31, 2021
December 31, 2020
December 31, 2019

Income tax (expense)
benefit:

December 31, 2021
December 31, 2020
December 31, 2019

Net income (loss):

$

$

(9) $
(10)
(21)

$

14
8
8

(15) $
(7)
(13)

$

9
10
—

(2) $
(2)
(4)

(1) $
—
—

(381) $
(632)
(770)

(2) $ — $ — $ — $ — $ — $
—
—

—
—

—
—

—
—

—
—

—
—

460
(266)
(290)

December 31, 2021
December 31, 2020
December 31, 2019

$ 2,196
309
134

$(2,512) $ (567) $

1,760
1,342

41
400

1
50
88

$ (413) $
(414)
274

(22) $
(101)
(109)

53
(1,021)
(1,204)

Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:

December 31, 2021
December 31, 2020
December 31, 2019

$

$

1
2
1

$

266
388
296

$

44
71
61

$

8
2
2

31
46
58

$ — $
—
—

$

48
91
69

— $
—
—

398
600
487

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

operating revenues:

For the year ended
December 31, 2021
December 31, 2020
December 31, 2019

Retail
$ (325) $ (1,272) $ (637) $ (42) $ (634) $ — $

Sunset

Texas

West

East

Asset
Closure

Corporate
and Other

(11)
8

677
575

(23)
195

(10)
41

(140)
168

—
—

Eliminations
(1)
1,719
(329)
(305)

— $
—
—

$

Consolidated

(1,191)
164
682

____________
(1) Amounts offset in fuel

ff

, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated

results.

(b) Income tax expense is generally not reflected in net income of the segments but is reflected almost entirely in Corporate

and Other net income.

156

21. SUPPLEMENTARY FINANCIAL INFORMATION

ii
Impaim rme

nt of Long-Lived Assets

In the second quarter of 2021, we recognized an impairment loss of $38 million related to our Zimmer generation facility
g a decrease in the economic
in Ohio as a result of a significant decrease in the estimated usefulff
forecast of the facilit
ity auction held in May
2021. The impairments are reported in our Sunset segment and include a $33 million write-down of property, plant and
equipment and a $5 million write-down of inventory.

evenues for the plant in the latest PJM capac

y and the inability to secure capac

life of the facilities, reflectin

t
ity r

a

a

ff

ff

In the third quarter of 2020, we recognized impairment losses of $173 million related to our Kincaid coal generation
facility in Illinois and $99 million related to our Zimmer coal generation facility in Ohio, each as a result of a significant
decrease in the estimated useful life of the facility, reflecff
ting our recently announced plan to retire both facilities by the end of
2027 in response to the final CCR rule (see Notes 4 and 13). The impairment losses are reported in our Sunset segment and
include a $260 million write-down of property, plant and equipment and a $12 million write-down of inventory.

ff

In the first quarter of 2020, we recognized an impairment loss of $52 million related to our Joppa/EEI coal generation
ting a decrease in the
facility in Illinois as a result of a significant decrease in the estimated useful life of the facility, reflecff
ast of the facility and changes to the operating assumptim on based on lower forecasted wholesale electricity
economic forec
ility and
prices. We also recorded a $32 million impairment to a capacity contract which was linked in part to the Joppa/EEI facff
therefore determined to have a significant decrease in estimated useful life. The impairments are reported in our Sunset
segment and include a $45 million write-down of property, plant and equipment, a $32 million write-down of intangible assets
and a $7 million write-down of inventory.

In determining the fair value of the impaired assets, we equally weighted a market approach based on transactions of

similar assets and an income approach discounting our projected cash flows through the respective plant retirement dates.

tt
Interes

t Expense

EE

and Relatell

s
d Charge

CC

Interest paid/accrued
Unrealized mark-to-market net (gains) losses on interest rate swapsa
Amortization of debt issuance costs, discounts and premiums
Debt extinguishment (gain) loss
Capita
Other
Total interest expense and related charges

alized interest

Year Ended December 31,

2021

2020

2019

$

$

480
(134)
30
1
(26)
33
384

$

$

467
155
18
(17)
(21)
28
630

$

$

576
220
9
(21)
(12)
25
797

The weighted average interest rate appl

a

icable to the Vistra Operations Credit Facilities, taking into account the interest

rate swapsa

discussed in Note 11, was 3.90%, 3.88% and 4.03% as of December 31, 2021, 2020 and 2019, respectively.

157

tt
Other

Income and Deductions

Other income:

Insurance settlements (a)
Gain on settlement of rail transportation disputes (b)
Sale of land (b)
Funds released from escrow to settle pre-petition claims of our
predecessor (c)
Interest income
All other

Total other income

Other deductions:

Loss on disposal of investment in NELP (d)

All other

Total other deductions

Year Ended December 31,

2021

2020

2019

$

$

$

$

88
15
9

—
—
28
140

$

$

— $
16
16

$

6
—
8

—
2
18
34

29
13
42

$

$

$

$

22
—
—

9
10
15
56

—
15
15

____________
(a) For the year ended December 31, 2021, $80 million reported in the Texas segment, $7 million reported in the Sunset
segment and $1 million reported in the Corporate and Other non-segment. For the year ended December 31, 2020, $3
million reported in the Corporate and Other non-segment, $2 million reported in the Asset Closure segment and $1 million
reported in the Texas segment. For the year ended December 31, 2019, reported in the Texas segment.

(b) Reported in the Asset Closure segment.
(c) Reported in the Corporate and Other non-segment.
(d) Reported in the East segment.

Restricted CasCC h

Amounts related to remediation escrow accounts

Total restricted cash

December 31, 2021

December 31, 2020

Current
Assets

Noncurrent
Assets

Current
Assets

Noncurrent
Assets

$
$

21
21

$
$

13
13

$
$

19
19

$
$

19
19

Remediation Escrow — During the years ended December 31, 2020 and 2019, Vistra transferred asset retirement
obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra
into an escrow accounts, and the funds are released to the remediation company as milestones are reached in the
deposits funds
remediation process. Amounts contractually payablea
to the third party in exchange for assuming the obligations are included in
other current liabilities and other noncurrent liabilities and deferred credits.

ff

Trade Accounts Rtt

eceivablell

Wholesale and retail trade accounts receivable
Allowance for uncollectible accounts
Trade accounts receivablea — net

December 31,

2021

2020

$

$

1,442
(45)
1,397

$

$

1,324
(45)
1,279

Gross trade accounts receivable as of December 31, 2021 and 2020 included unbilled retail revenues of $426 million and

$468 million, respectively.

158

Allowance forff Uncollectible Accounts Receivable

Allowance forff
Increase forff
Decrease forff

uncollectible accounts receivable at beginning of period (a)
bad debt expense
account write-offs

$

Allowance for uncollectible accounts receivablea
____________
(a) The beginning balance in 2020 includes a $6 million increase recorded dued

at end of period

$

Instruments—Credit Losses (see Note 1).

Inventories by Major Category

e

Materials and supplies
Fuel stock
Natural gas in storage
Total inventories

Investments

Nuclear plant decommissioning trust
Assets related to employee benefit plans (Note 17)
Land
Miscellaneous other
Total investments

Year Ended December 31,

2021

2020

2019

45
110
(110)
45

$

$

42
110
(107)
45

$

$

19
82
(65)
36

to the adoption of ASU 2016-13, Financial

December 31,

2021

2020

260
314
36
610

$

$

260
236
19
515

December 31,

2021

2020

1,960
42
44
3
2,049

$

$

1,674
41
44
—
1,759

$

$

$

$

Investment in Unconsolidat

edtt

ll

ii
Subsidiary

On the Merger Date, we assumed Dynegy's 50% interest in NELP, a joint venturet

with NextEra Energy, Inc., which

indirectly owned the Bellingham NEA facility and the Sayreville facility.

In December 2019, Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc.,

indirect
subsidiaries of Vistra, entered into a transaction agreement with NELP and certain indirect subsidiaries of NextEra Energy, Inc.
wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP in exchange for 100% ownership interest
in NJEA, the company which owns the Sayreville facility. The NELP Transaction was approve
d by FERC in February 2020,
and the NELP Transaction closed on March 2, 2020. As a result of the NELP Transaction, Vistra indirectly owns 100% of the
Sayreville facff
lity. A loss of $29 million was
between our derecognized investment in NELP
recognized in connection with the NELP Transaction, reflecting the difference
and the value of our acquired 100% interest in NJEA, which was measured in accordance with ASC 805. The loss is reported
in our consolidated statements of operations in other deductions.

ility and no longer has any ownership interest in the Bellingham NEA faci

a

ff

ff

Equity earnings related to our investment in NELP totaled $3 million and $14 million for the years ended December 31,
2020 and 2019, respectively, recorded in equity in earnings of unconsolidated investment in our consolidated statements of
operations. We received distributions totaling $3 million and $22 million for the years ended December 31, 2020 and 2019,
respectively.

159

Nuclear Decommissi

ii

TT
oning Tn

rust

ff

Investments in a trust that will be used to fundff

value. Decommissioning costs are being recovered fromff

the costs to decommission the Comanche Peak nuclear generation plant are
Oncor customers as a delivery fee surcharge over the
carried at fair
life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and
expense, including gains and losses associated with the trust fund assets and the decommissioning liabia lity, are offset by a
corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and
Oncor's
deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. If funds recovered fromff
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, provided that
Vistra complied with PUCT ruler
s and regulations regarding decommissioning trusts. A summary of the fair market value of
investments in the fund

follows:

ff

Year Ended December 31,

2021

2020

$

679
1,281
1,960

618
1,056
1,674

Debt securities (a)
Equity securities (b)

$

Total
____________
(a) The investment objective for debt securities is to invest in a diversifieff d tax efficient portfolio with an overall portfolio
rating of AA or above as graded by S&P or Aa2 by Moody's. 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 2.54% and
2.91% as of December 31, 2021 and 2020, respectively, and an average maturity of 10 years as of both December 31,
2021 and 2020.

$

$

(b) The investment objective for equity securities is to invest tax efficiently and to match the performff

ance of the S&P 500

Index for U.S. equity investments and the MSCI EAFE Index forff

non-U.S. equity investments.

Debt securities held as of December 31, 2021 mature as follows: $247 million in one to five years, $190 million in five to

10 years and $242 million after 10 years.

The following tabla e summarizes proceeds from sales of securities and investments in new securities.

Year Ended December 31,

2021

2020

2019

$
$

483
$
(505) $

433
$
(455) $

431
(453)

Proceeds from sales of securities
Investments in securities

operty, Pyy

laPP nt and Equipment

Power generation and structures
Land
Office and other equipment

Total

Less accumulated depreciation

Net of accumulated depreciation

December 31,

2021

2020

16,195
608
183
16,986
(4,801)
12,185
173
212
486
13,056

$

$

15,222
617
173
16,012
(3,614)
12,398
182
207
712
13,499

$

$

Finance lease right-of-use assets (net of accumulated depreciation)
Nuclear fuel (net of accumulated amortization of $125 million and $91 million)
Construction work in progress

Property, plant and equipment — net

preciation expenses totaled $1.478 billion, $1.377 billion and $1.300 billion for the years ended December 31, 2021,

2020 and 2019, respectively.

160

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. The estimated remaining useful lives
range from 1 to 32 years for our property, plant and equipment.

Asset Retireii ment and MiningMM

Reclamll

ation Obligations

tt

(ARO)O

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining,
remediation or closure of coal ash basins, and generation plant disposal costs. There is no earnings impact with respect to
changes in the nuclear plant decommissioning liability, as all costs are recoverablea
through the regulatory process as part of
delivery fees charged by Oncor. As of December 31, 2021 and 2020, asbestos removal liabilities totaled $3 million and zero
million, respectively. We have also identified conditional AROs for asbestos removal and disposal, which are specific to
certain generation assets.

As of December 31, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled
$1.635 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs
to ultimately decommission that plant are recoverablea
through the regulatory rate making process as part of Oncor's delivery
fees, a corresponding regulatory liability has been recorded to our consolidated balance sheet of $325 million in other
noncurrent liabilities and deferred credits.

The following tablea

summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in

our consolidated balance sheets, for the years ended December 31, 2021, 2020 and 2019:

Nuclear Plant
Decommissioning
1,276
$

Mining Land
Reclamation

Coal Ash and
Other

Total

$

442

$

655

$

2,373

Liability at December 31, 2018
Additions:
Accretion
Adjustment for change in estimates
Adjustment for obligations assumed through
acquisitions

Reductions:
Payments
Liability transfers (a)

Liability at December 31, 2019
Additions:
Accretion
Adjustment for change in estimates (b)

Reductions:
Payments
Liability transfers (a)

Liability at December 31, 2020
Additions:
Accretion
Adjustment for change in estimates

Reductions:
Payments

Liability at December 31, 2021

Less amounts dued

currently

44
—

—

—
—
1,320

46
219

—
—
1,585

50
—

—
1,635
—
1,635

$

22
16

—

(70)
—
410

20
(6)

(65)
—
359

16
13

(68)
320
(90)
230

$

31
(1)

(3)

(39)
(135)
508

23
25

(49)
(15)
492

22
1

(20)
495
(14)
481

$

97
15

(3)

(109)
(135)
2,238

89
238

(114)
(15)
2,436

88
14

(88)
2,450
(104)
2,346

Noncurrent liability at December 31, 2021

$

(a) Represents ARO transferred

remediation. Any remaining unpaid third-party obligation has been
reclassififf ed to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance
sheets.

to a third-party forff

ff

161

(b) The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2020. Under
applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash
flows occur, and the PUCT requires a new cost estimate at least every five years. The increase in the liability was driven
equipment and services and a delay in timing of when the
by changes in assumptim ons including increased costs for labor,
U.S. Department of Energy is estimated to begin accepting spent fuel offsite.

a

NN
Other Noncurre

ii
nt Liabil

itll iett s and Deferre

e

d CreCC ditstt

The balance of other noncurrent liabilities and deferred credits consists of the folff

lowing:

ities (Note 6)

Retirement and other employee benefits (Note 17)
Winter Storm Uri impact (a)
Identifiable intangible liabila
Regulatory liability
Finance lease liabilities
Uncertain tax positions, including accrued interest
Liability for third-party remediation
Accrued severance costs
Other accrued expenses

December 31,

2021

2020

276
261
147
325
235
13
17
39
176
1,489

$

$

312
—
289
89
206
12
31
54
138
1,131

$

$

Total other noncurrent liabilities and deferred credits
____________
(a)

Includes the allocation of ERCOT default uplift charges and future bill credits related to large commercial and industrial
customers that curtailed during Winter Storm Uri.

Fair Vii

alueVV

of Debt

Long-term debt (see Note 11):
Long-term debt under the Vistra Operations
Credit Facilities
Vistra Operations Senior Notes
Forward Capac
ity Agreements
Equipment Financing Agreements
Building Financing
Other debt

a

December 31, 2021

December 31, 2020

Fair Value
Hierarchy

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

$

Level 2
Level 2
Level 3
Level 3
Level 2
Level 3

$

2,549
7,880
211
85
3
3

$

2,518
8,193
211
85
3
3

$

2,579
6,634
45
59
10
3

2,565
7,204
45
59
10
3

determine fair value in accordance with accounting standards as discussed in Note 15. 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.

Supplemll

ental Cash Flowll

Information

The following tablea

reconciles cash, cash equivalents and restricted cash reported in our consolidated statements of cash

flows to the amounts reported in our consolidated balance sheets at December 31, 2021 and 2020:

Cash and cash equivalents
Restricted cash included in current assets
Restricted cash included in noncurrent assets

Total cash, cash equivalents and restricted cash

December 31,

2021

2020

$

$

1,325
21
13
1,359

$

$

406
19
19
444

162

The folff

lowing table summarizes our supplemental cash flowff

information for the years ended December 31, 2021, 2020

and 2019, respectively.

Cash payments related to:

Interest paid
Capita

alized interest

Interest paid (net of capitalized interest)
Income taxes paid / (refunds received) (a)
ncing activities:

Noncash investing and finaff

Accrued property, plant and equipment additions (b)
Disposition of investment in NELP
Acquisition of investment in NJEA
Shares issued for tangible equity unit contracts (Note 14)
Land transferred with liabia lity transfers

Year Ended December 31,

2021

2020

2019

$

$
$

$
$
$
$
$

$

482
(26)
456
$
(50) $

$
171
— $
— $
— $
— $

$

503
(21)
482
$
(140) $

$
19
$
123
90
$
— $
— $

525
(12)
513
(76)

67
—
—
446
16

____________
(a) For the years ended December 31, 2021, 2020 and 2019, we paid state income taxes of $52 million, $40 million and $42
of zero, $170 million and $115 million, respectively, and received state

ff

million, respectively, received federal tax refunds
tax refunds of $2 million, $10 million and $3 million, respectively.

(b) Represents property, plant and equipment accruals during the period for which cash has not been paid as of the end of the

period.

163

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 finaff
ncial officer, of the effectiveness of the design and operation of the disclosure controls and
procedures (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) in effect at December 31, 2021.
Based on the evaluation performed, our principal executive officer and principal finaff
ncial officer concluded that the disclosure
controls and procedures were effecff

tive as of that date.

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(e)
and 15a-15(e) of the Exchange Act) 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 CORP.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING

shing and maintaining adequate internal control over financial
The management of Vistra Corp. is responsible for establia
reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Vistra
Corp.'s internal control over financial reporting is designed to provide reasonable assurance regarding the reliabia lity of financial
reporting and the preparation of financial statements forff
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.

The management of Vistra Corp. performed an evaluation of the effectiveness of the company's internal control over financial
reporting as of December 31, 2021 based on the Committee of Sponsoring Organizations of the Treadway Commission's
(COSO's) Internal Control - InteII
Framework (2013). Based on the review perforff med, management believes that as of
e
grated
December 31, 2021 Vistra Corp.'s internal control over finaff

ncial reporting was effective.

The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated finaff
statements of Vistra Corp. has issued an attestation report on Vistra Corp.'s internal control over finaff

ncial reporting.

ncial

/s/ CURTIS A. MORGAN
Curtis A. Morgan
Chief Executive Officer
(Principal Executive Officer)

February 25, 2022

/s/ JAMES A. BURKE
James A. Burke
President and Chief Financial Officer
(Principal Financial Officer)

164

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To hthe sto khckh ldolders

dand hthe Boa drd of

iDirectors of

iVistra Corp.

O iOpi inion on Internal CControl over Fiinan icial Reportinging

audit ded hthe iinte

control over fifina

l
We hhave
l
rnal
di
icrite iria establiblia
Dece bmber 31, 2021, bbas ded on
of
i
respects, effectiive iinte
Control

gOrga inizatiions of hthe Treaddwayy Com imi
control over
ifina
l
ework (2013) iiss dued byby COSO.

l
rnal
d FramFF

e
t — InteII
grate

h dshed iin InteI

Sponsori gng

inci lal

inci lal

i
reporti gng of
rnal Control

iVistra Corp.
e
grate
tt — InteII
ission ((CO )SO). In our
i i
i

dand iits s b idi
d FramFF

ubsidia irie (s ( hthe “Company”)ny”) as of
ework (2013) iissued bd byy thhe Commiittee
opinion, hthe Compa yny maiint iai dned, iin lalll materiiall
rnal

reporti gng as of Dece bmber 31, 2021, bbas ded on

ished iin InteI

establi h d
bl

icrite iria

di

auditedd, iin ac
We hhave lalso
consoliddat ded fifina
((PCAOB)), hthe
li
bruary 25, 2022, expressedd an unqualilififiedd o i ipinion on hthose fifina
report ddat ded February

iwithh thhe sta d d
inci lal statements as of

ndards of hthe

dcordance

dand for hthe yyear e d dnded Dece bmber 31, 2021, of hthe Compa yny
inci lal statements.

Public Com ypany Accountinging Ove irsightght Boa drd (

bli

(Unitedd States))
dand our

i

Basiis ffor O ipi inion

ibl

hThe Compa yny’s ma gnagement iis res
assessment of hthe effec itiveness of iinternall cont
l
Annuall Report on Inte
rnal
iinternall cont
inci lal
requi dred to bbe i dinde
lrules a dnd regul

regulatiions of hthe Sec iuritiies a dnd Exchange

reporti gng bbas ded on our

Control over
l

lrol over fifina

dpendent

iFina

i

i

inci lal Re

ponsible forff maiint iainingning effectiive iinte
lrol over fifina

control over fifina
reporti gng, iincl dluded id in thhe accompanying

inci lal

rnal
l

i

l

i

porti gng. Our res
di

audit. We are a p bliublic accountinging fifirm regi

ponsibilili yty iis to express an

ibi

i

inci lal

reporti gng
dand for iits
nying Ma gnagement’s
opinion on hthe Compa yny’s
register ded i hwith hthe PCAOB a dnd are
applicablblea
li

i i

iwithh respect to thhe Compa yny iin ac

dcordance

iwithh thhe U.S. f dfede lral securi iities llaws a dnd hthe

hange Com imi

ission

dand hthe PCAOB.

di

dconduct ded our

audi it in acc dordance

We
audit to obbtaiin reasonablblea
di
mate iriall respects. Our
audi
di
hthat a materi lial weakkness e ixists, tes iti gng
assessedd ri kisk,
provides a reasonablblea
provide

bbasiis for our

opinion.
i i

dunderstanding
dand evallua iti gng hthe ddesignign
id

assurance babout
it incl dludedd obbtai iini gng an

iwithh thhe sta d d

hwhe hther effectiive iinte

ndards of hthe PCAOB. hThose sta d d
ndards
control over fifina
rnal
l
nding of iinternall cont

inci lal
lrol over fifina

l

i

i
require hthat we lplan a dnd perform hthe
reporti gng was m iaint iai dned iin lalll
reporti gng, asse issi gng hthe iriskk
inci lal
lrol bbas ded on hthe
audit
di

i

dand performinging suchh o hther proceddures as we

conside dred necessa yry iin hthe icircumstances. We b lbeliieve hthat our

dand opera iti gng effectiiveness of if internall cont

Defi

fini ition and Li

tations fof Internal CControl over Fiinan icial Reportinging
i
imi

i

i

i

l

i

inci lal

iunti gng

iityy of fiinaff

l
rnal
inci lal

dand hthe preparatiion of fifina

iprinci liples. A com ypany’s iinte

reporti gng iis a process d idesignedgned to

control over fifina
reporti gng

A com ypany’s iinte
lreliiabilbila
accep dted acco
htha (t ( )1) pert iain to thhe maiintenance of rec dords hthat, iin reasonablblea
didisposiitiions of hthe assets of hthe compa yny; ( )(2)
ppreparatiion of fifina
expe dinditures
com ypany;
didisposiitiion of hthe compa yny’s assets hthat c

of hthe compa yny are b ibei gng madde onlyonly iin ac
gregarding
bl

sonable assurance
inci lal statements for externall purpose is in acc dordance
lipoli icies

gregarding
rding hthe
iwi hth ggene lrallyly
dand proceddures
dand
sonable assurance hthat transac itions are record dded as necessa yry to permiit
dand
dand didirectors of hthe
quisitiion, use, or

reporti gng iincl dludes thhose
fl

rding preve intion or itimelyly ddetec ition of unauth ihoriz ded ac

iwi hth ggene lrallyly accep dted acco

uthoriza itions of ma gnagement

iprinci liples, a dnd hthat rec ieipts

id
provide rea
dcordance

ddet iaill, accuratelytely and fd f iaifff

inci lal statements iin ac

reflect thhe transac itions

ieri lal effect on hthe fifina

sonable assurance

control over fifina

inci lal statements.

lould hd have a mat

iwithh a h i

provide rea
id

provide rea
id

dcordance

dand ( )(3)

iunti gng

inci lal

rnal
l

rlyrly

i i

bl

bl

t

l

i

is i hnherent lili

Because of iit
proje
projectiions of
becbecause of change

yany evallua ition of effectiiveness to future

imitations, iinternall cont

i
inci lal
iperi dods are subje
onditiions, or hthat thhe ddeggree of com lipliance wi hith hthe

lrol over fifina

hange is in c di

i

reporti gng mayy not prevent or ddetect miisstatements.
subject to hthe i krisk hthat cont

lAlso,
lrols may by become iin dadequate

lipoli icies or proceddures may dy det

ieriorate.

/ //s/ Del iloitte & Touchhe LLP

Dallllas, Texas
February

bruary 25, 2022

165

Item 9B. OTHER INFORMATION

On February 2rr

3, 2022, our board of directors (Board) approved our amended and restated bylaws (A&R Bylaws)
effective immediately. The A&R Bylaws were amended and restated, among other things, to amend advance notice
requirements forff
stockholders to bring proposed director nominees or other items of business before a special or annual
stockholders meeting, and to allow annual meetings of stockholders to be held by means of remote communication in addition
to being held at any place, as determined by our Board in its sole discretion. The A&R Bylaws also reflect other technical and
administrative changes.

The foregoing description of our A&R Bylaws is qualified in its entirety by the full text of the A&R Bylaws, a copy of

which is included as Exhibit 3.5 to this Annual Report on Form 10-K.

Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

166

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Code of Ethics

PART III

Vistra has adopted a code of ethics entitled "Vistra Code of Conduct" that applies to directors, officers and employees,
e
It may be accessed through the "Corporat
including the chief executive officer and senior financial officers of Vistra.
Governance" section of the Company's website at www.vistracorp.com. Vistra 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 will disclose such events within four
business days following the date of the amendment or
on this website for at least a 12-month period. A copy of the "Vistra Code
waiver, and such information will remain availablea
of Conduct" is availablea

in print to any stockholder who requests it.

r

ff

Other information required by this Item is incorporated by reference to the similarly named section of Vistra Definitive

Proxy Statement for its 2022 Annual Meeting of Stockholders.

Item 11. EXECUTIVE COMPENSATION

Information required by this Item is incorporated by reference to the similarly named section of Vistra's Definitive Proxy

Statement for its 2022 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's Definff

itive Proxy Statement for its 2022 Annual Meeting of Stockholders.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACT

RR

IONS, 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's Definitive Proxy Statement for its 2022 Annual Meeting
of Stockholders.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this Item is incorporated by reference to the sections entitled "Principal Accounting Fees" in

Vistra's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders.

Deloitte & Touche LLP's PCAOB ID Number is 34.

167

Item 15. EXHIBITS AND 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)

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS
(Millions of Dollars)

RR

Depreciation and amortization
Selling, general and administrative expenses

Operating loss

Other income
Interest expense and related charges
Impacts of Tax Receivable Agreement
Loss before income tax benefit

Income tax benefit
Equity in earnings of subsidiaries, net of tax

Net income (loss)

See Notes to the Condensed Financial Statements.

Year Ended December 31,

2021

2020

2019

$

$

(17) $
(53)
(70)
3
—
53
(14)
4
(1,264)
(1,274) $

(15) $
(72)
(87)
5
(7)
5
(84)
25
695
636

$

(7)
(62)
(69)
12
(88)
(37)
(182)
42
1,068
928

VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(Millions of Dollars)

Cash flows — operating activities:

Cash used in operating activities

Ended December 31,

2021

2020

2019

$

(38) $

(86) $

(58)

Cash flows — investing activities:
t

al expenditures
Capita
Dividend received fromff
Equity contribution to subsidiaries

subsidiaries

Cash provided by investing activities

Cash flows — finaff

ncing activities:

Issuances of preferred stock
Repayments/repurchases of debt
Debt tender offer and other debt financing fees
Stock repurchases
Dividends paid to stockholders
Other, net

Cash used in financing 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

$

—
405
(988)
(583)

2,000
—
—
(471)
(290)
(23)
1,216
595
73
668

$

(15)
1,105
—
1,090

—
(747)
(17)
—
(266)
—
(1,030)
(26)
99
73

$

(36)
3,890
—
3,854

—
(2,903)
(123)
(656)
(243)
—
(3,925)
(129)
228
99

See Notes to the Condensed Financial Statements.

VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(Millions of Dollars)

ASSETS

Cash and cash equivalents
Trade accounts receivablea — net
Income taxes receivable
Prepaid expense and other current assets

Total current assets

iated companies

Investment in affilff
Property, plant and equipment — net
Identifiable intangible assets — net
Accumulated deferred income taxes
Other noncurrent assets
Total assets

LIABILITIES AND EQUITY

Trade accounts payable
Accounts payablea —affiliates
Accrued taxes
Other current liabilities

Total current liabilities

Tax Receivablea
Other noncurrent liabilities and deferred debits

Agreement obligations

Total liabilities
Total stockholders' equity
Total liabilities and equity

See Notes to the Condensed Financial Statements.

December 31,

2021

2020

$

$

$

$

668
8
15
1
692
7,157
3
31
1,016
1
8,900

114
72
—
3
189
394
25
608
8,292
8,900

$

$

$

$

73
7
—
5
85
8,005
3
47
783
2
8,925

2
74
14
4
94
447
23
564
8,361
8,925

NOTES TO CONDENSED FINANCIAL STATEMENTS

1.

BASIS OF PRESENTATION

The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of
ncial
operations and cash flows of Vistra Corp. (Parent). Certain information and footnote disclosures normally included in finaff
statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules of the SEC. Because the
unconsolidated condensed financial statements do not include all of the information and footnotes required by U.S. GAAP, they
should be read in conjunction with the financial statements and related notes of Vistra Corp. and Subsidiaries included in the
under
annual report on Form 10-K for the year ended December 31, 2020. Vistra Corp.'s subsidiaries have been accounted forff
the equity method. All dollar amounts in the financial statements and tablea
s in the notes are stated in millions of U.S. dollars
unless otherwise indicated.

Vistra Corp. (Parent) filff es a consolidated U.S. federal income tax return.

Consolidated tax expenses or benefits and
deferred tax assets or liabilities have been allocated to the respective subsidiaries in accordance with the accounting rules that
apply to separate finff ancial statements of subsidiaries.

t

169

2.

RESTRICTIONS ON SUBSIDIARIES

a

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, 2021, Vistra Operations can
distribute approxi
mately $7.3 billion to Vistra Corp. (Parent) under the Credit Facilities Agreement without the consent of any
party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra
Operations to Vistra Corp. (Parent) of approxi
mately $405 million, $1.1 billion and $3.9 billion during the years ended
December 31, 2021, 2020 and 2019, respectively. Additionally, Vistra Operations may make distributions to Vistra Corp.
(Parent) in amounts sufficient for Vistra Corp. (Parent) to make any payments required under the TRA oRR
r the Tax Matters
Agreement or, to the extent arising out of Vistra Corp. (Parent)'s ownership or operation of Vistra Operations, to pay any taxes
or general operating or corporate overhead expenses. As of December 31, 2021, all of the restricted net assets of Vistra
Operations may be distributed to Vistra Corp. (Parent).

a

3. GUARANTEES

Vistra Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that could require
performance or payment under certain conditions. As of December 31, 2021, there are no material outstanding claims related to
guarantee obligations of Vistra Corp. (Parent), and Vistra Corp. (Parent) does not anticipate it will be required to make any
material payments under these guarantees in the near term.

4.

DIVIDEND RESTRICTIONS

Under applicable law, Vistra Corp. (Parent) is prohibited fromff

paying any dividend to the extent that immediately

following payment of such dividend there would be no statutt ory surplus or Vistra Corp. (Parent) would be insolvent.

Vistra Corp. (Parent) received $405 million, $1.105 billion and $3.890 billion in dividends from its consolidated
subsidiaries in the years ended December 31, 2021, 2020 and 2019, respectively. In the year ended December 31, 2021, Vistra
Corp. (Parent) made an equity contribution to Vistra Operation of $988 million.

(c)

EXHIBITS:

Vistra Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2021

Exhibits

Previously Filed With File
Number*

As
Exhibit

(2)

2.1

2.2

(3(i))

3.1

3.2

3.3

3.4

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

001-38086
Form 8-K
(filed May 4, 2020)

001-38086
Form 8-K
(filed June 29, 2020)

001-38086
Form 8-K
(filed on October 15, 2021)

001-38086
Form 8-K (filed
on December 13, 2021)

2.1

2.1

— Order of the United States Bankruptcy Court for the District of
Delaware Confirming the Third Amended Joint Plan of
Reorganization

— Agreement and Plan of Merger, dated as of October 29, 2017, by
and between Vistra Energy Corp. (now known as Vistra Corp.rr
) and
Dynegy, Inc.

3.1

— Restated Certificate of Incorporation of Vistra Energy Corp. (now

known as Vistra Corp.)

3.1

— Certificate of Amendment of

of
Incorporation of Vistra Energy Corp. (now known as Vistra Corp.)
,
effeff ctive July 2, 2020

the Restated Certificate

rr

ff

3.1

— Series A Preferred Stock Certificate of Designation, filed with the

Secretary of State of Delaware on October 14, 2021

3.1

— Series B Preferred Stock Certificate of Designation, filed with the

Secretary of State of Delaware on December 9, 2021

(3(ii))

By-laws

170

3.5

(4)

4.1

4.2

4.3

4.4

4.5

4.6

4.7

4.8

4.9

4.10

Exhibits

Previously Filed With File
Number*

As
Exhibit

**

— Amended and Restated Bylaws of Vistra Corp., effective Februarr

ryrr

23, 2022

Instruments Defining the Rights of Security Holders, Including Indentures

001-38086
Form 8-K
(filed on August 23, 2018)

4.1

— Indenturet

for 5.500% Senior Note due 2026, dated as of August 22,
the
2018, among Vistra Operations Company LLC, as issuer,
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee

001-38086
Form 8-K
(filed on August 23, 2018)

001-38086
Form 8-K
(filed on August 23, 2018)

001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)

001-38086
Form 10-K (Year ended
December 31, 2019) (filed
on February 28, 2020)

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

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)

4.5

— First Supplemental Indenturet

for the 5.500% Senior Notes due
2026, dated August 30, 2019, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.36 — Second Supplemental Indenturet

2026, dated October 25, 2019,
Subsidiaries,
Trustee

the Company,

for the 5.500% Senior Notes dued
among the Guaranteeing
the Subsidiary Guarantors and the

4.5

4.6

4.8

4.9

4.3

— Third Supplemental Indenturet

2026, dated January 31, 2020,
Subsidiaries,
Trustee

the Company,

for the 5.500% Senior Notes due
among the Guaranteeing
the Subsidiary Guarantors and the

— Fourth Supplemental Indenturet

for the 5.500% Senior Notes dued
2026, dated March 26, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

— Fifth Supplemental Indenturet

for the 5.500% Senior Notes due
2026, dated October 7, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

— Sixth Supplemental Indenturet

for the 5.500% Senior Notes due
2026, dated January 8, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

— Seventh Supplemental Indenturet

for the 5.500% Senior Notes dued
2026, dated July 29, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

— Eighth Supplemental Indenturet

for the 5.500% Senior Notes due
2026, dated December 28, 2021, among the Guaranteeing
Subsidiaries,
the Subsidiary Guarantors and the
Trustee

the Company,

4.11

**

4.12

4.13

001-38086
Form 8-K
(filed on February 6, 2019)

4.1

— Indenturet

for 5.625% 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

rr

001-38086
Form 8-K
(filed on February 6, 2019)

4.2

— Form of Rule 144A Global Security for 5.625% Senior Note due

2027 (included in Exhibit 4.1)

171

Exhibits

4.14

4.15

4.16

4.17

4.18

4.19

4.20

4.21

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on February 6, 2019)

001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)

001-38086
Form 10-K (Year ended
December 31, 2019) (filed
on February 28, 2020)

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

4.22

**

As
Exhibit
4.3

4.6

— Form of Regulation S Global Security for 5.625% Senior Note due

2027 (included in Exhibit 4.1)

— First Supplemental Indenturet

for the 5.625% Senior Notes due
2027, dated August 30, 2019, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.41 — Second Supplemental Indenturet

2027, dated October 25, 2019,
Subsidiaries,
Trustee

the Company,

for the 5.625% Senior Notes dued
among the Guaranteeing
the Subsidiary Guarantors and the

4.7

4.8

— Third Supplemental Indenturet

2027, dated January 31, 2020,
Subsidiaries,
Trustee

the Company,

for the 5.625% Senior Notes due
among the Guaranteeing
the Subsidiary Guarantors and the

— Fourth Supplemental Indenturet

for the 5.625% Senior Notes dued
2027, dated March 26, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.17 — Fifth Supplemental Indenturet

for the 5.625% Senior Notes due
2027, dated October 7, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.18 — Sixth Supplemental Indenturet

for the 5.625% Senior Notes due
2027, dated January 8, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.4

— Seventh Supplemental Indenturet

for the 5.625% Senior Notes dued
2027, dated July 29, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

— Eighth Supplemental Indenturet

for the 5.625% Senior Notes due
2027, dated December 28, 2021, among the Guaranteeing
Subsidiaries,
the Subsidiary Guarantors and the
Trustee

the Company,

4.23

4.24

4.25

4.26

4.27

001-38086
Form 8-K
(filed on June 24, 2019)

4.1

— Indenturet

for 5.00% Senior Notes dued

2027, dated as of June 21,
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 June 24, 2019)

001-38086
Form 8-K
(filed on June 24, 2019)

001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)

001-38086
Form 10-K (Year ended
December 31, 2019) (filed
on February 28, 2020)

4.2

— Form of Rule 144A Global Security for 5.00% Senior Notes due

2027 (included in Exhibit 4.1)

4.3

— Form of Regulation S Global Security for 5.00% Senior Notes due

2027 (included in Exhibit 4.1)

4.7

— First Supplemental Indenturet

for the 5.000% Senior Notes due
2027, dated August 30, 2019, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.46 — Second Supplemental Indenturet

2027, dated October 25, 2019,
Subsidiaries,
Trustee

the Company,

for the 5.000% Senior Notes dued
among the Guaranteeing
the Subsidiary Guarantors and the

172

Exhibits

4.28

4.29

4.30

4.31

4.32

Previously Filed With File
Number*

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

4.33

**

As
Exhibit
4.9

— Third Supplemental Indenturet

2027, dated January 31, 2020,
Subsidiaries,
Trustee

the Company,

for the 5.000% Senior Notes due
among the Guaranteeing
the Subsidiary Guarantors and the

4.10 — Fourth Supplemental Indenturet

for the 5.000% Senior Notes dued
2027, dated March 26, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.26 — Fifth Supplemental Indenturet

for the 5.000% Senior Notes due
2027, dated October 7, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.27 — Sixth Supplemental Indenturet

for the 5.000% Senior Notes due
2027, dated January 8, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

4.5

— Seventh Supplemental Indenturet

for the 5.000% Senior Notes dued
2027, dated July 29, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee

— Eighth Supplemental Indenturet

for the 5.000% Senior Notes due
2027, dated December 28, 2021, among the Guaranteeing
Subsidiaries,
the Subsidiary Guarantors and the
Trustee

the Company,

4.34

4.35

4.36

4.37

4.38

4.39

4.40

4.41

001-38086
Form 8-K
(filed on June 17, 2019)

001-38086
Form 8-K
(filed on June 17, 2019)

001-38086
Form 8-K
(filed on June 17, 2019)

001-38086
Form 8-K
(filed on June 17, 2019)

001-38086
Form 8-K
(filed on June 17, 2019)

001-38086
Form 8-K
(filed on June 17, 2019)

4.1

— Indenture,

t

dated as of June 11, 2019, between Vistra Operations
Issuer, and Wilmington Trust, National

Company LLC, as
Association, as Trustee

4.2

— Supplemental Indenturet

for 3.55% Senior Secured Notes due 2024
and 4.30% Senior Secured Notes Due 2029, dated as of June 11,
2019, among Vistra Operations Company LLC, as Issuer,
the
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee

4.3

— Form of Rule 144A Global Security for 3.55% Senior Notes due

2024 (included in Exhibit 4.2)

4.4

— Form of Rule 144A Global Security for 4.30% Senior Notes due

2029 (included in Exhibit 4.2)

4.5

— Form of Regulation S Global Security for 3.55% Senior Notes due

2024 (included in Exhibit 4.2)

4.6

— Form of Regulation S Global Security for 4.30% Senior Notes due

2029 (included in Exhibit 4.2)

001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)

001-38086
Form 8-K (filed
on November 21, 2019)

4.8

4.1

— Second Supplemental Indenturet

for 3.55% Senior Secured Notes
2029, dated as of
due 2024 and 4.30% Senior Secured Notes dued
August 30, 2019, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors
and the Trustee

— Third Supplemental Indenturet

for 3.55% Senior Secured Notes dued
2024 and 4.30% Senior Secured Notes dued
2029, dated as of
October 25, 2019, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, Subsidiary Guarantors and
the Trustee

173

Exhibits

4.42

Previously Filed With File
Number*

001-38086
Form 8-K (filed
on November 21, 2019)

As
Exhibit
4.2

— Fourth Supplemental Indenture,

dated as of November 15, 2019,
among Vistra Operations Company LLC, as Issuer, the Subsidiary
Guarantors (as defined therein), and Wilmington Trust, National
Association, as Trustee

t

4.43

4.44

4.45

4.46

4.47

4.48

4.49

001-38086
Form 8-K (filed
on November 21, 2019)

001-38086
Form 8-K (filed
on November 21, 2019)

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

4.50

**

001-38086
Form 8-K
(filed on May 11, 2021)

001-38086
Form 8-K
(filed on May 11, 2021)

001-38086
Form 8-K
(filed on May 11, 2021)

4.51

4.52

4.53

4.54

4.3

— Form of Rule 144A Global Security for 3.70% Senior Note due

2027 (included in Exhibit 4.2)

4.4

— Form of Regulation S Global Security for 3.70% Senior Note due

2027 (included in Exhibit 4.2)

4.11 — Fifth Supplemental Indenturet

2024, 3.70% Senior Secured Notes dued
Secured Notes dued
Vistra Operations Company LLC, as Issuer,
Subsidiaries, the Subsidiary Guarantors and the Trustee

for 3.55% Senior Secured Notes dued
2027 and 4.30% Senior
2029, dated as of January 31, 2020, among
the Guaranteeing

4.12 — Sixth Supplemental Indenturet

for 3.55% Senior Secured Notes dued
2024, 3.70% Senior Secured Notes dued
2027 and 4.30% Senior
Secured Notes due 2029, dated as of March 26, 2020, among Vistra
Operations Company LLC,
the Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee

Issuer,

as

4.41 — Seventh Supplemental Indenturet

for 3.55% Senior Secured Notes
due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
2029, dated as of October 7, 2020, among Vistra
Secured Notes dued
Operations Company LLC,
the Guaranteeing
Issuer,
Subsidiaries, the Subsidiary Guarantors and the Trustee

as

4.42 — Eighth Supplemental Indenturet

for 3.55% Senior Secured Notes
due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
Secured Notes due 2029, dated as of January 8, 2021, among Vistra
Operations Company LLC,
the Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee

Issuer,

as

4.6

4.1

— Ninth Supplemental Indenturet

for 3.55% Senior Secured Notes due
2024, 3.70% Senior Secured Notes dued
2027 and 4.30% Senior
Secured Notes due 2029, dated as of July 29, 2021, among Vistra
Operations Company LLC,
the Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee

Issuer,

as

— Tenth Supplemental Indenturet

2024, 3.70% Senior Secured Notes dued
Secured Notes dued
Vistra Operations Company LLC, as Issuer,
Subsidiaries, the Subsidiary Guarantors and the Trustee

for 3.55% Senior Secured Notes due
2027 and 4.30% Senior
2029, dated as of December 28, 2021, among
the Guaranteeing

— Indenturet

for 4.375% Senior Notes due 2029, dated as of May 10,
2021, between Vistra Operations Company LLC, as Issuer, the
Subsidiary Guarantors,
Trust, National
Association, as Trustee

and Wilmington

4.2

— Form of Rule 144A Global Security for 4.375% Senior Notes dued

2029 (included in Exhibit 4.1)

4.3

— Form of Regulation S Global Security for 4.375% Senior Notes due

2029 (included in Exhibit 4.1)

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

4.7

— First Supplemental Indenturet

for the 4.375% Senior Notes due
2029, dated July 29, 2021, among Vistra Operations Company
LLC, as Issuer,
the Subsidiary
the Guaranteeing Subsidiaries,
Guarantors and the Trustee

174

Previously Filed With File
Number*

As
Exhibit

Exhibits

4.55

**

— Second Supplemental Indenturet

for the 4.375% Senior Notes dued
2029, dated December 28, 2021, among Vistra Operations
Company LLC, as Issuer,
the
Subsidiary Guarantors and the Trustee

the Guaranteeing Subsidiaries,

4.56

4.57

4.58

4.59

4.60

4.61

4.62

4.63

4.64

4.65

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 April 5, 2019)

4.7

4.8

4.1

— Purchase and Sale Agreement dated as of August 21, 2018, between
TXU Energy Retail Company LLC as originator, and TXU Energy
Receivablea

s Company LLC, as purchaser

— Receivablea

Purchase Agreement dated as of August 21, 2018,
among TXU Energy Receivablea
s Company LLC, as seller, TXU
Energy Retail Company LLC, as servicer, Vistra Operations
Company LLC, as perforff mance guarantor, certain purchaser agents
and purchasers named therein and Credit Agricole Corporate and
Investment Bank, as administrator

— First Amendment to Purchase and Sale Agreement, dated as of
April 1, 2019, among TXU Energy Retail Company LLC, Dynegy
Energy Services, LLC, and Dynegy Energy Services (East), LLC,
each as an originator, and TXU Energy Receivablea
s Company LLC,
as purchaser

001-38086
Form 10-Q (Quarter ended
June 30, 2019) (filed on
August 2, 2019)

4.12 — Second Amendment to Purchase and Sale Agreement, dated as of
June 3, 2019, among TXU Energy Retail Company LLC, Dynegy
Energy Services, LLC, and Dynegy Energy Services (East), LLC,
each as an originator, and TXU Energy Receivablea
s Company LLC,
as purchaser

001-38086
Form 8-K
(filed on July 19, 2019)

001-38086
Form 8-K
(filed on October 16, 2020)

001-38086
Form 8-K
(filed on December 28,
2020)

001-38086
Form 8-K
(filed on April 5, 2019)

4.1

4.1

4.1

4.2

— Third Amendment to Purchase and Sale Agreement, dated as of
July 15, 2019, among TXU Energy Retail Company LLC, Dynegy
Energy Services, LLC, and Dynegy Energy Services (East), LLC,
s Company LLC,
each as an originator, and TXU Energy Receivablea
as purchaser

— Fourth Amendment to Purchase and Sale Agreement, dated as of
October 9, 2020, among TXU Energy Retail Company LLC, as an
originator and servicer, the other originators named therein, and
TXU Energy Receivables Company LLC, as purchaser

— Fifth Amendment to Purchase and Sale Agreement, dated as of
December 21, 2020, among TXU Energy Retail Company LLC,
certain originators named therein, and TXU Energy Receivablea
s
Company LLC, as purchaser

— First Amendment to Receivablea

s Purchase Agreement, dated as of
April 1, 2019, among TXU Energy Receivablea
s Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator

001-38086
Form 10-Q (Quarter ended
June 30, 2019) (filed on
August 2, 2019)

4.13 — Second Amendment to Receivablea

s Purchase Agreement, dated as
s Company LLC,
of June 3, 2019, among TXU Energy Receivablea
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator

001-38086
Form 8-K
(filed on July 19, 2019)

4.2

— Third Amendment to Receivablea

s Purchase Agreement, dated as of
July 15, 2019, among TXU Energy Receivablea
s Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator

175

Exhibits

4.66

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on July 16, 2020)

As
Exhibit
4.1

— Fifth Amendment to Receivablea

s Purchase Agreement, dated as of
s Company LLC, as
July 13, 2020, among TXU Energy Receivablea
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator

— Sixth Amendment to Receivablea

s Purchase Agreement, dated as of
October 9, 2020, among TXU Energy Receivablea
s Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator

— Seventh Amendment to Receivablea

s Purchase Agreement, dated as
of December 21, 2020, among TXU Energy Receivablea
s Company
LLC, as seller, TXU Energy Retail Company LLC, as servicer,
Vistra Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator

4.2

4.2

4.56 — Eighth Amendment to Receivablea

s Purchase Agreement, dated as
of February 19, 2020, among TXU Energy Receivablea
s Company
LLC, as seller, TXU Energy Retail Company LLC, as servicer,
Vistra Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator

4.6

4.1

4.2

4.1

— Ninth Amendment to Receivablea

s Purchase Agreement, dated as of
March 26, 2021, among TXU Energy Receivablea
s Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator

— Tenth Amendment to Receivablea

s Purchase Agreement, dated as of
s Company LLC, as
July 9, 2021, among TXU Energy Receivablea
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator

— Eleventh Amendment to Receivablea

s Purchase Agreement, dated as
of July 16, 2021, among TXU Energy Receivablea
s Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as perforff mance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator

— Warrant Agreement, dated February

2, 2017, by and among
r
Dynegy, Computershare Inc. and Computershare Trust Company,
N.A., as warrant agent

4.2

— Supplemental Warrant Agreement, dated as of April 9, 2018 among

the Company and the Warrant Agent

4.1

— Form of Warrant

001-38086
Form 8-K
(filed on October 16, 2020)

001-38086
Form 8-K
(filed on December 28,
2020)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-Q (Quarter ended
March 31, 2021) (filed on
May 4, 2021)

001-38086
Form 8-K
(filed on July 15, 2021)

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

001-33443
Form of 8-K
(filed on February 7, 2017)

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
(fileff d December 23, 2016)

4.1

**

Material Contracts

— Registration Rights Agreement, by and among TCEH Corp.rr

(now
) and the Holders party thereto, dated as of

known as Vistra Corp.rr
October 3, 2016

— Description of Capia tal Stock

176

4.67

4.68

4.69

4.70

4.71

4.72

4.73

4.74

4.75

4.76

4.77

(10)

Exhibits

Previously Filed With File
Number*

As
Exhibit

Management Contracts; Compensatory Plans, Contracts and Arrangements

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

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)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)

001-38086
Form 8-K
(filed on May 23, 2019)

001-33443
Form10-K (Year ended
December 31, 2018) (filed
on February 28, 2019)

001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)

001-38086
Form 8-K
(filed May 4, 2018)

10.6 — 2016 Omnibus Incentive Plan

10.7 — Form of Option Award Agreement

(Management)

Omnibus Incentive Plan (pre-2021 awards)

for 2016

10.8 — Form of Restricted Stock Unit Award Agreement (Management)
for 2016 Omnibus Incentive Plan (pre-2021 awards)

10(d) — Form of Performance Stock Unit Award Agreement for 2016

Omnibus Incentive Plan (pre-2021 awards)

10.5 — Form of Option Award Agreement
Omnibus Incentive Plan

(Management)

for 2016

10.6 — Form of Restricted Stock Unit Award Agreement (Management)

for 2016 Omnibus Incentive Plan

10.7 — Form of Restricted Stock Unit Award Agreement (Director) for

2016 Omnibus Incentive Plan

10.8 — Form of Performance Stock Unit Award Agreement for 2016

Omnibus Incentive Plan

10.9 — Vistra Corp. Executive Annual Incentive Plan

10.1 — Amended and Restated 2016 Omnibus Incentive Plan, effective as

of May 20, 2019

10.7 — Vistra Equity Deferred Compensation Plan forff Certain Directors,

effective as of January 1, 2019

10.13 — Amendment No. 1 to the Vistra Equity Deferre

ff

d Compensation

Plan, dated effecff

tive as of February

rr

24, 2021

10.1 — Amended and Restated Employment Agreement, dated as of May 1,
2018, between Curtis A. Morgan and Vistra Energy Corp. (now
known as Vistra Corp.)

177

Exhibits

10.14

Previously Filed With File
Number*

001-33443
Form 10-Q (Quarter ended
March 31, 2019) (filed on
May 3, 2019)

As
Exhibit
10.5 — Amended and Restated Employment Agreement, dated May 1,
2019, between James A. Burke and Vistra Energy Corp. (now
known as Vistra Corp.)

10.15

10.16

10.17

10.18

10.19

10.20

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)

10.22 — Employment Agreement between Stephanie Zapata Moore and

Vistra Energy Corp. (now known as Vistra Corp.)

10.23 — Employment Agreement between Carrie Lee Kirby and Vistra

Energy Corp. (now known as Vistra Corp.)

001-38086
Form 8-K
(filed February 27, 2020)

10.2 — Employment Agreement between Scott A. Hudson, Vistra Energy
) and TXU Retail Service

Corp. (now known as Vistra Corp.rr
Company

001-38086
Form 8-K
(filed February 27, 2020)

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)

10.1 — Employment Agreement between Stephen J. Muscato, Vistra
) and Luminant Energy

(now known as Vistra Corp.rr

Energy Corp.rr
Company LLC

10.26 — Form of indemnification agreement with directors

10.29 — Stock Purchase Agreement, dated as of October 25, 2016, by and
) and Curtis A.

(now known as Vistra Corp.rr

between TCEH Corp.rr
Morgan

10.21

Credit Agreements and Related Agreements

333-215288
Form S-1
(fileff d December 23, 2016)

333-215288
Form S-1
(fileff d 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)

001-38086
Form 8-K
(filed December 14, 2017)

10.22

10.23

10.24

10.25

10.26

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.

rr

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.

rr

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.

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.

178

Exhibits

10.27

Previously Filed With File
Number*

001-38086
Form 8-K
(filed February 22, 2018)

10.28

001-38086
Form 8-K
(filed June 15, 2018)

10.29

001-38086
Form 8-K
(filed April 4, 2019)

10.30

001-38086
Form 8-K
(filed May 29, 2019)

10.31

001-38086
Form 8-K (filed
on November 21, 2019)

As
Exhibit
10.1 — Sixth Amendment to Credit Agreement, dated as of February 20,
0, 2018), by and among Deutsche Bank
2018 (effective Februarr
AG New York Branch, Vistra Operations Company LLC, Vistra
Intermediate Company LLC and the other Credit Parties and
Lenders party thereto.

ry 2rr

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.

10.4 — Eighth Amendment to Credit Agreement, dated March 29, 2019, by
and among Vistra Operations Company LLC, Vistra Intermediate
Company LLC, the other Credit Parties (as defined in the Vistra
Operations Credit Agreement) party thereto, Bank of Montreal,
Chicago Branch, as new Revolving Loan Lender, Revolving Letter
of Credit Issuer and Joint Lead Arranger, the various other Lenders
and Letter of Credit Issuers party thereto, and Credit Suisse as
Administrative Agent and Collateral Agent

10.1 — Ninth Amendment to Credit Agreement, dated May 29, 2019, by
and among Vistra Operations Company LLC, Vistra Intermediate
Company LLC, the other Credit Parties (as defined in the Vistra
Operations Credit Agreement) party thereto, Sun Trust Bank, as
incremental Revolving Loan Lender, and Credit Suisse AG,
Cayman Island Branch, as Administrative Agent and Collateral
Agent

10.1 — Tenth Amendment to the Credit Agreement, dated November 15,
2019, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
other Credit Parties (as defined in the Credit Agreement) party
(as defined in the Credit
thereto,
Agreement) party thereto, Credit Suisse AG, Cayman Islands
Branch (as the 2019 Incremental Term Loan Lender and as
Administrative Agent and as Collateral Agent), and the other
Lenders party thereto

the other Credit Parties

10.32

10.33

10.34

10.35

10.36

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 June 7, 2019)

001-38086
Form 8-K
(filed on June 7, 2019)

001-38086
Form 8-K (filed
on November 13, 2019)

10.1 — Purchase Agreement, dated June 4, 2019, 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

10.2 — Purchase Agreement, dated June 6, 2019, by and among Vistra
Operations Company LLC and Goldman Sachs & Co. LLC, on and
behalf of itself and the several Initial Purchasers named in Schedule
I to the Purchase Agreement

10.1 — Purchase Agreement, dated November 6, 2019, by and among
Vistra Operations Company LLC and J.P. Morgan Securities LLC,
on behalf of itself and the several Initial Purchases named in
Schedule I to the Purchase Agreement

179

Exhibits

10.37

Previously Filed With File
Number*

001-38086
Form 8-K (filed
on May 11, 2021)

10.38

10.39

10.40

10.41

10.42

10.43

10.44

10.45

10.46

001-38086
Form 8-K (filed
on October 15, 2021)

001-38086
Form 8-K (filed
on December 13, 2021)

001-38086
Form 8-K (filed
on April 2, 2021)

001-38086
Form 8-K (filed
on April 2, 2021)

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)

10.47

001-38086
Form 8-K
(filed on June 15, 2018)

As
Exhibit
10.1 — Purchase Agreement, dated May 5, 2021, 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

10.1 — Purchase Agreement, dated October 12, 2021, by and between

Vistra Corp. and Goldman Sachs & Co. LLC

10.1 — Purchase Agreement, dated December 7, 2021, by and between

Vistra Corp. and Goldman Sachs & Co. LLC

10.1 — Credit Agreement, dated as of March 29, 2021, among Vistra
Operations Company LLC (as Borrower), Vistra Intermediate
Company LLC (as Holdings), Royal Bank of Canada (as
Administrative Agent and as Collateral Agent), and the 2021
Incremental Term Loan Lender (as definff ed therein)

10.2 — First Amendment to Credit Agreement, dated as of April 1, 2021,
among Vistra Operations Company LLC (as Borrower), Vistra
Intermediate Company LLC (as Holdings), Royal Bank of Canada
(as Administrative Agent and as Collateral Agent), and the 2021
Incremental Term Loan Lender (as definff ed therein)

10.10 — Assumption Agreement, dated as of April 9, 2018, between Vistra
) (as successor by merger
Energy Corp. (now known as Vistra Corp.rr
to Dynegy Inc.), and Credit Suisse AG, Cayman Islands Branch, as
Administrative Agent and as Collateral Trustee.

10.11 — Guarantee and Collateral Agreement, dated as of April 23, 2013,
among Dynegy Inc., the subsidiaries of the borrower fromff
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).

10.12 — Joinder, dated as of April 9, 2018, among Vistra Energy Corp. (now
), the subsidiary guarantors party thereto and

known as Vistra Corp.rr
Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee.

10.13 — 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 fromff
rated by reference to
Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc.
filed on April 24, 2013).

time to time (incorpor

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 firff st-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

180

Exhibits

10.48

Previously Filed With File
Number*

001-38086
Form 8-K
(filed on June 15, 2018)

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.

10.49

10.50

10.51

10.52

10.53

10.54

10.55

10.56

10.57

10.58

10.59

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)

10.13 — Tax Receivablea

(now known as Vistra Corp.rr
Company, as transfer agent, dated as of October 3, 2016

Agreement, by and between TEX Energy LLC
) and American Stock Transfer & Trust

10.14 — Tax Matters Agreement, by and among TEX Energy LLC (now
), EFH Corp., Energy Future Intermediate
known as Vistra Corp.rr
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
) and TEX
Corp., TEX Energy LLC (now known as Vistra Corp.rr
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(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

001-38086
Form 8-K
(filed on October 16, 2020)

10.1 — Master Framework Agreement, dated as of October 9, 2020, by and
among TXU Energy Retail Company LLC, as seller and seller party
agent, certain originators named therein, and MUFG Bank, Ltd., as
buyer

001-38086
Form 8-K
(filed on July 15, 2021)

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

001-38086
Form 8-K
(filed on October 16, 2020)

10.1 — Amendment No. 1 to Master Framework Agreement, dated as of

July 1, 2021, by and among TXU Energy Retail Company LLC, as
seller and seller party agent, certain originators named therein,
Vistra Operations Company LLC, as guarantor, and MUFG Bank,
Ltd., as buyer

10.2 — Amendment No. 2 to Master Framework Agreement, dated as of

August 3, 2021, by and among TXU Energy Retail Company LLC,
as seller and seller party agent, certain originators named therein,
Vistra Operations Company LLC, as guarantor, and MUFG Bank,
Ltd., as buyer

10.2 — Master Repurchase Agreement, dated as of October 9, 2020,
between TXU Energy Retail Company LLC and MUFG Bank, Ltd.

181

Exhibits

10.60

10.61

Previously Filed With File
Number*

001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)

As
Exhibit
10.3 — Amendment No. 1 to Master Repurchase Agreement, dated as of
August 3, 2021, between TXU Energy Retail Company LLC and
MUFG Bank, Ltd.

001-38086
Form 8-K
(filed on December 28,
2020)

10.1 — Joinder Agreement, dated as of December 21, 2020, among TXU
seller party agent, Vistra
Energy Retail company LLC, as
Operations Company LLC, as guarantor, certain originators named
therein, and MUFG Bank, Ltd., as buyer

10.62

**

10.63

**

— Amendment No. 2 to Master Repurchase Agreement, dated as of
December 30, 2021, between TXU Energy Retail Company LLC
and MUFG Bank, Ltd.

— Credit Agreement, dated as of February

4, 2022, among Vistra
Operations Company LLC, as Borrower, Vistra Intermediate
Company LLC, as Holdings, Citibank, N.A., as Administrative
Agent and as Collateral Agent, and the other lenders party thereto.

r

Subsidiaries of the Registrant

**

Consent of Experts

**

— Significant Subsidiaries of Vistra 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

**

**

Section 1350 Certifications

***

32.2

***

(95)

95.1

Mine Safety Disclosures

**

XBRL Data Files

101.INS

**

101.SCH **

101.CAL **

101.DEF

**

101.LAB **

101.PRE

**

— Certification of Curtis A. Morgan, principal executive officer of
Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of
2002

— Certification of James A. Burke, principal finaff

ncial officer of Vistra

Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

— Certification of Curtis A. Morgan, principal executive officer of
Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002

— Certification of James A. Burke, principal finaff

ncial officer of Vistra
Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

— Mine Safety Dt

isclosures

— The following financial information from Vistra Corp.'s Annual
Report on Form 10-K for the period ended December 31, 2021
formatted in Inline XBRL (Extensible Business Reporting
Language) includes: (i) the Consolidated Statements of Operations,
(ii) the Consolidated Statements of Comprehensive Income, (iii)
the Consolidated Statements of Cash Flows, (iv) the Consolidated
Balance Sheets, (v) the Consolidated Statement of Changes in
Equity and (vi) the Notes to the Consolidated Financial Statements.

— XBRL Taxonomy Extension Schema Document

— XBRL Taxonomy Extension Calculation Linkbase Document

— XBRL Taxonomy Extension Definition Linkbase Document

— XBRL Taxonomy Extension Labea

l Linkbase Document

— XBRL Taxonomy Extension Presentation Linkbase Document

182

— The Cover Page Interactive Data File does not appear in Exhibit
104 because its XBRL tags are embedded within the Inline XBRL
document.

Previously Filed With File
Number*

As
Exhibit

Exhibits

104

____________________
*
**
***

Incorporated herein by reference
Filed herewith
Furnished herewith

Item 16. FORM 10-K SUMMARY

None.

183

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Vistra Corp. has duly caused this
report to be signed on its behalf by the undersigned, thereunto dulyd

authorized.

SIGNATURES

Date: February 2rr

5, 2022

VISTRA CORP.
By

/s/ CURTIS A. MORGAN
Curtis A. Morgan (Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
cities and on the date indicated.
persons on behalf of Vistra Corp. and in the capaa

Signature

Title

Date

/s/ CURTIS A. MORGAN
(Curtis A. Morgan, Chief Executive Officer)

ff

/s/ JAMES A. BURKE
(James A. Burke, President and Chief Financial Officer)

/s/ CHRISTY DOBRY
(Christy Dobry, Senior Vice President and Controller)

/s/ SCOTT B. HELM
(Scott B. Helm, Chairman of the Board)

/s/ HILARY E. ACKERMANN
(Hilary E. Ackermann)

Principal Executive Officer
and Director

February 25, 2022

Principal Financial Officer

February 25, 2022

Principal Accounting Officer

February 2rr

5, 2022

Chairman of the Board and
Director

February 25, 2022

Director

February 25, 2022

/s/ ARCILIA C. ACOSTA
(Arcilia C. Acosta)

/s/ GAVIN R. BAIERARR
(Gavin R. Baiera)

/s/ PAUL M. BARBAS
(Paul M. Barbas)

/s/ LISA CRUTRR CHFIELD
(Lisa Crutchfield)

/s/ BRIAN K. FERRAIOL
I
(Brian K. Ferraioli)

RR

/s/ JEFF D. HUNTER

(Jeff Dff

. Hunter)

/s/ JOHN R. SULT
(John R. Sult)

Director

February 25, 2022

Director

February 25, 2022

Director

February 25, 2022

Director

February 25, 2022

Director

February 25, 2022

Director

February 25, 2022

Director

February 2rr

5, 2022

184

INFORMATION FOR STOCKHOLDERS

Stock Exchange Listing

NYSE: VST

Corporate Headquarters

Vistra Corp.

6555 Sierra Drive 

Irving, Texas 75039

Stock Transfer Agent and Registrar

Please direct general questions about stockholder 
accounts, stock certiﬁcates, transfer of shares, or 
duplicate mailings to Vistra’s transfer agent:

American Stock Transfer & Trust Company, LLC 

6201 15th Avenue

Brooklyn, NY 11219

Phone: (800) 937-5449

Email: info@amstock.com

Board of Directors † 

Hilary E. Ackermann (4)*

Arcilia C. Acosta (2,3)

Gavin R. Baiera (2)*

Paul M. Barbas (3)*

Lisa Crutchﬁeld (3,4)

Brian K. Ferraioli (1)*

Scott B. Helm,
Chairman of the Board of Directors

Jeff D. Hunter (1,4)

Curtis A. Morgan

John R. Sult (1,2)

1 Audit Committee

2 Social Responsibility and Compensation Committee

3 Nominating and Governance Committee

4 Sustainability and Risk Committee

Independent Registered Accounting Firm

* Committee Chair

† As of April 4, 2022. Besides Curtis A. Morgan, all members
of the Vistra Board of Directors satisfy the independence 
requirements of the Securities and Exchange Commission
and the NYSE.

Deloitte & Touche LLP

Officer Certiﬁcations

Our Annual Report on Form 10-K ﬁled with the
SEC is included herein, excluding all exhibits. 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 investor relations contact 
details, are available on our website at 
www.vistracorp.com.

6555 Sierra Drive, Irving, Texas 75039(cid:5)| www.vistracorp.com