2019 ANNUAL REPORT
2019 ANNUAL REPORT
Upton 2 Solar and Energy Storage Facility
ABOUT VISTRA ENERGY
Vistra Energy (NYSE:VST) is a premier, integrated, Fortune
350 energy company based in Irving,Texas, providing
essential resources for customers, commerce, and
communities. Vistra combines an innovative, customer-
centric approach to retail with safe, reliable, diverse,
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products and services to market in 20 states and the District
of Columbia, including six of the seven competitive retail
markets in the U.S. and markets in Canada and Japan, as
well. Serving nearly 5 million residential, commercial, and
industrial retail customers with electricity and gas, Vistra is
the largest competitive residential electricity provider in the
country and offers over 40 renewable energy plans. The
company is also the largest competitive power generator
in the U.S. with a capacity of approximately 39,000
megawatts powered by a diverse portfolio of natural gas,
nuclear, coal, solar, and battery energy storage facilities. In
addition, the company is a large purchaser of wind power.
The company is currently developing the largest battery
storage system of its kind in the world — a 300-MW/1,200-
MWh system in Moss Landing, California. Vistra is guided
by four core principles: we do business the right way, we
work as a team, we compete to win, and we care about our
people, our neighbors, and our stakeholders.
DEAR FELLOW VST STOCKHOLDERS
We referred to 2019 as the “Year of Execution” for Vistra
Energy Corp. — and that it was. We focused our efforts
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returning capital to stockholders, and capturing our
Dynegy merger synergy targets. Not only did we
accomplish those goals, but we also continued to
demonstrate the stability and strength of our integrated
business model, expanded our retail footprint to be the
largest competitor in the high-margin U.S. residential
electricity markets with the acquisitions of Crius Energy
Trust (“Crius”) and Ambit Energy (“Ambit”), released a
10-year outlook for our company indicating the long-
term resilience of our business, and formalized our
commitment to take actions to address climate change by
announcing greenhouse gas emissions reduction targets
and by joining the Climate Leadership Council
as a founding member.
Our success in 2019 and positive outlook for the year
ahead are a direct result of executing on our business
objectives with a focus and dedication to excellence.
Importantly, the vastly different business model and asset
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had in 2019 and in each of the four years since Vistra has
been a public company — and will similarly position the
company to continue our transformation in the age of
climate change, leading to what we believe will be long-
term strength and sustainability. I am pleased to share
with you some of the highlights from 2019 and a vision
for a sustainable future.
Delivering on Financial Commitments and
Returning Capital
Vistra continued to prove out the stability of the
integrated model in 2019, delivering adjusted EBITDA
from our ongoing operations of $3.393 billion1, which
marked the fourth year in a row — every year since Vistra
has been a public company — that we have delivered
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from ongoing operations was $2.437 billion1, results
that exceeded the high end of our guidance range and
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of nearly 72%. Vistra’s ability to generate this robust free
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to both invest selectively in attractive opportunities and
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In fact, in 2019, we instituted a dividend program at
$0.50 per share on an annualized basis and spent
more than $650 million under our existing $1.75 billion
VISTRA ENERGY | 2019 ANNUAL REPORT
Our success in 2019 and positive
outlook for the year ahead are a
direct result of executing on our
business objectives with a focus
and dedication to excellence.
Curt Morgan
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share repurchase program, collectively returning
approximately $900 million to stockholders. We also
invested approximately $880 million on the Crius
and Ambit acquisitions, which were executed at an
average of 3.9 times enterprise value to EBITDA and
were immediately accretive to Vistra’s EBITDA per share
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approximately $8.3 billion of debt, reducing our
annualized, after-tax interest expense by approximately
$95 million. In total, since becoming a public company
nearly four years ago, Vistra has returned approximately
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repurchases, debt retirement, and recurring and
special dividends.
As we look ahead to 2020, our capital allocation focus is
squarely on progressing toward our long-term leverage
target of 2.5 times net debt to EBITDA. Whereas we
dubbed 2019 the “Year of Execution,” 2020 is the “Year of
Financial Strength and Capital Allocation Clarity.”
A strong balance sheet is the foundation of our business
model — low leverage levels and the achievement of
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to weather commodity cycles while positioning our
management team to make sound investment decisions
at the right times in the business cycles. Low leverage
levels also support our ability to convert approximately 65
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giving Vistra the ability to implement a diverse capital
allocation plan.
1
Vistra has already announced an 8% increase to our
dividend program for 2020, an increase that was at the
high end of our expected 6–8% annual growth rate and
which is supported by our stable and growing EBITDA
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to further evaluate the appropriate size of our future
dividends as part of our long-term capital allocation
plan, which we expect to roll out in the second part of
this year. We anticipate our long-term capital allocation
plan will call for continued prudent and disciplined
growth investments using on average about a quarter of
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dividends and share repurchases.
Capturing Merger Synergies and Driving
Operational Performance Improvement
Vistra’s relentless focus on cost management and synergy
capture is just another way we are creating value for
our stockholders. Vistra closed the merger with Dynegy
in April 2018, and in 2019, as we approached the full
integration of the businesses, we realized approximately
$270 million of the $290 million of full run-rate EBITDA
synergies. The $290 million synergy target represents
a nearly 30% increase from the $225 million of annual
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Vistra has also been able to capture merger value
through our Operations Performance Improvement
(“OPI”) program. The OPI program, which is designed to
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cost-effectively as possible, has transformed the culture
of our generation, mining, and procurement operations.
Importantly, our OPI efforts have put our generation
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landscape evolves in the markets where we operate.
Vistra initially announced an expectation to achieve $125
million of annual OPI EBITDA enhancements, and we
have since more than tripled that target to $425 million
per year. In 2019, we realized $220 million from OPI; we
expect to be at the full run-rate by year-end 2021.
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the merger continue to materialize, with Vistra now
forecasting to achieve an annual run-rate of $320
million — an increase of nearly 400% above our initial
projections — with $210 million realized in 2019. Finally,
Vistra continues to believe we will be able to use the
approximately $4 billion of Dynegy net operating loss
carry forwards we inherited in the Dynegy merger,
resulting in approximately $900 million in present value
tax savings. The Dynegy merger continued to prove its
value in 2019, and with integration now largely complete,
we are moving forward as one company, set for success.
Top: Vistra employees volunteering through the company’s
employee-led volunteer program Energy in Action
Middle: TXU Energy Bike MS team participates in Bike MS
Round-Up Ride 2019
Bottom: Kendall Power Plant celebrates acceptance into
OSHA VPP Star Program
2
Operating Integrated Retail and Generation
Businesses
Another cornerstone of Vistra’s success is our integrated
business model. Pairing our retail and wholesale
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which we believe leads to consistent results and a more
attractive investment. This is true, in part, because of the
stability of our retail business and the in-the-money nature
of our generation assets.
Retail
On the retail side, Vistra acquired two retailers in 2019,
Crius and Ambit, adding strong brands to our retail
portfolio and improving our generation-to-retail load
match to nearly 60%, a 20% increase since the Dynegy
acquisition. Following these transactions, Vistra’s retail
business operates in 19 states and the District of
Columbia, has an industry-leading 26% market share
across all U.S. competitive retail markets, and is the largest
competitive electric retailer in the U.S. in the high-margin
residential market.
Also in 2019, Vistra introduced two new brands,
Brighten Energy and Better Buy, which supply affordable
renewable energy options to customers in Illinois, Ohio,
and Pennsylvania. Within the Texas markets, TXU Energy
continued its legacy of innovative, customer-centric
products by launching two new plans: TXU Energy Free
PassSM, giving customers free electricity on the seven days
a month they use it the most, and TXU Energy Pure SolarSM,
which gives consumers the option to turn any electricity
plan into a renewable solar plan. These new products,
combined with our current portfolio of electricity plans,
sophisticated sales channel management, and brand
strength, led to our Texas retail team growing residential
customer counts for the second year in a row.
2019 Retail Volumes
Business
Residential
Muni-Agg
Crius
Ambit
52%
27%
13%
5%
2%
Generation
Vistra’s generation assets are relatively young, highly
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from gas-fueled generation and more than 50% of our
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combined cycle gas turbines. We expect these gas assets
VISTRA ENERGY | 2019 ANNUAL REPORT
will be a long-term critical resource for the electric grid,
which is becoming increasingly dependent on intermittent
renewable resources.
Our assets performed exceptionally well in 2019.
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approximately 95% compared to a target of 94%. This
metric is critical to our operational success, as it measures
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when the assets are in the money. As we move into
2020, we will continue to focus on achieving superior
commercial availability and maintaining the reliability of
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tight supply/demand dynamics.
To provide reliable generation to our customers, we must
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No. 1 priority — our people are our most important asset.
As of Dec. 31, 2019, Vistra had 11 generation sites that
have achieved VPP STAR status, the highest designation of
OSHA’s Voluntary Protection Programs, with 6 progressing
toward this impressive distinction. During the year, we also
rolled out a new company-wide safety program called Best
Defense, which focuses on high-risk activities and adds
defenses to ensure that if we fail, we do so safely. As we
did in 2019, we will continue to emphasize the importance
of safety in our operations and will always strive for zero
incidents, accidents, and near-misses.
Also in 2019, Vistra continued to transform our generation
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impactful technologies with the retirement of four coal
plants in downstate Illinois, along with the announcement
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We also initiated and continue to support legislation in
Illinois, the Coal to Solar and Energy Storage Act, that
would provide a pathway to reinvest and repurpose
existing coal-fueled power plant sites into solar and
battery energy storage facilities, helping Illinois meet its
clean energy goals while continuing to support economic
vitality in impacted local communities. The repowering
at existing power plant sites is part of our Environmental
Justice strategy to bring no- to low-emitting resources
to communities while using existing infrastructure and
bringing tax base.
Growing the Business
In addition to completing the Crius and Ambit retail
acquisitions in 2019, we continued to advance our battery
storage business in California with the 300-MW/1,200-
MWh Moss Landing project under construction and the
execution of an agreement to develop a 20-MW battery
storage project at our Oakland site — further examples
3
of utilizing existing sites to bring environmentally
friendly technology to consumers of electricity. The
300-MW/1,200-MWh project located at our Moss Landing
site is expected to be online in the fourth quarter of 2020
and is one of the world’s largest battery projects of its kind.
The Moss Landing site is a world-class industrial site that
has the capacity and existing infrastructure for substantial
additional battery storage — and in a market like California
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storage, we expect we will be able to grow our operations
at this site in the future.
In addition to the growth potential at our Moss Landing
site, Vistra has a line of sight to a deep pipeline
of renewable and battery projects, along with a
demonstrated capability to identify, close, and capture
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our ability to deploy on average a quarter of our free
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opportunities in the next several years.
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Sustainability has become one of the most important
priorities for companies — and it certainly is for Vistra.
As an energy company with fossil fuels as part of its fuel
source, Vistra must be a leader on climate change and
provide stakeholders, most notably investors, with a view
of our future and long-term sustainability. An important
action Vistra took in 2019 was the announcement of
our formalized commitment to combat climate change
through long-term emissions reduction targets.
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reduction in CO2 equivalent emissions by 2030 and an
80% reduction in CO2 equivalent emissions by 2050, each
as compared to a 2010 baseline. We further announced
an aspiration to achieve net-zero carbon emissions by
2050 if advancements in technology, market constructs,
and public policy are supportive. As of Dec. 31, 2019,
including the impact of retiring the four Illinois coal
plants, we have reduced our CO2 equivalent emissions
by 42% compared to a 2010 baseline — meaning we
have already achieved nearly 85% of our 2030 emissions
reduction goal.
Vistra is not just taking action independently to reduce
our carbon footprint — we are taking a leadership role
in the effort to advance climate change policies on a
national basis. In 2019, we joined the Climate Leadership
Council (CLC) as a founding member, advocating for a
consistently applied carbon fee and dividend approach
as the ideal public policy solution to appropriately
incentivize investments in carbon-free and carbon-
reducing technologies. We further committed to
contribute $1 million to Americans for Carbon Dividends,
the advocacy arm of the CLC. Vistra believes the CLC’s
bipartisan climate roadmap, which promotes a national
carbon dividend framework, is the right public policy
solution to facilitate the country’s transition to a lower-
carbon future while maintaining the strength of the
American economy.
Finally, Vistra formalized its sustainability governance
structure in 2019, expanding the responsibility of the risk
committee of our board of directors to include oversight
of our sustainability program and naming a chief
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and governance disclosures will be a key strategic focus
for us in 2020. As such, please keep an eye out for our
2019 Sustainability Report, which will be released in June.
It is imperative that Vistra transform our company
over the next several years to support its long-term
sustainability. This transformation must be accomplished
in an economically prudent fashion utilizing Vistra’s
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and power and natural gas capabilities. Vistra’s 10-
year view, shown below, provides a glimpse into the
potential transformation of our business, forecasting an
asset mix that we believe will support electric system
reliability while providing customers with cost-effective
energy that meets their sustainable preferences and
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Ennis Power Plant
4
VISTRA ENERGY | 2019 ANNUAL REPORT
When I look ahead to the next 10 years, I see a sustainable
company furthering its success. Our unique capabilities,
with expertise managing risk, operating assets with scale
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services to our retail customers, make us well-positioned
to capitalize on the transition to a lower-carbon economy,
improving our environmental footprint while continuing
to create value for our stockholders over the long-term.
Our history has demonstrated that we have the discipline
to be good stewards of your capital, returning meaningful
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growth only when attractive opportunities arise. We remain
optimistic that through continued execution and delivering
on our commitments, investors will realize that we have
a company with the ability to sustain performance and
results over the long run, and our stock price will ultimately
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Thank you for your interest in Vistra — we look forward to
the year ahead!
Sincerely,
Curt Morgan
Curt Morgan
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transformation is possible while also leaving Vistra with
meaningful capital to return to shareholders. Notably,
this 10-year view assumes Vistra will retire another
approximately 7,200 MW of coal generation and invest
in approximately 6,000 MW of renewables and battery
storage between now and 2030.
2020E EBITDA
2030E EBITDA
Retail
Coal
Gas
Nuclear
Renewable
26%
17%
51%
6%
0.5%
In Closing
Retail
Coal
Gas
Nuclear
Renewable
27%
9%
41%
5%
18%
It is amazing to look back over three and a half years
to October 2016, when our predecessor emerged
from bankruptcy, and see how much our team has
accomplished — enhancing safety practices and
performance, growing EBITDA by more than 100%,
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(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:79)(cid:72)(cid:91)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:74)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:372)(cid:72)(cid:72)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:82)(cid:81)(cid:72)(cid:3)
(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:3)(cid:80)(cid:88)(cid:70)(cid:75)(cid:3)(cid:79)(cid:82)(cid:90)(cid:72)(cid:85)(cid:3)(cid:70)(cid:68)(cid:85)(cid:69)(cid:82)(cid:81)(cid:3)(cid:73)(cid:82)(cid:82)(cid:87)(cid:83)(cid:85)(cid:76)(cid:81)(cid:87)(cid:17)(cid:3)(cid:54)(cid:83)(cid:72)(cid:70)(cid:76)(cid:403)(cid:70)(cid:68)(cid:79)(cid:79)(cid:92)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)
grown the business through both investments in solar and
(cid:69)(cid:68)(cid:87)(cid:87)(cid:72)(cid:85)(cid:92)(cid:3)(cid:86)(cid:87)(cid:82)(cid:85)(cid:68)(cid:74)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:77)(cid:72)(cid:70)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:70)(cid:84)(cid:88)(cid:76)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:87)(cid:3)(cid:74)(cid:68)(cid:86)
assets and retail businesses — all executed at attractive
returns well in excess of our internal investment threshold.
(cid:50)(cid:89)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:68)(cid:80)(cid:72)(cid:3)(cid:83)(cid:72)(cid:85)(cid:76)(cid:82)(cid:71)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:76)(cid:80)(cid:72)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:68)(cid:79)(cid:86)(cid:82)(cid:3)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:76)(cid:403)(cid:72)(cid:71)(cid:3)(cid:81)(cid:72)(cid:68)(cid:85)(cid:79)(cid:92)
$1.5 billion of annual cost savings through merger
synergies and internal restructuring activities and returned
nearly $5 billion to our stakeholders. All of this was made
possible because of our low leverage, low-cost integrated
model, which now has a four-year demonstrated track
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(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:3)(cid:89)(cid:72)(cid:85)(cid:92)(cid:3)(cid:75)(cid:76)(cid:74)(cid:75)(cid:3)(cid:70)(cid:82)(cid:81)(cid:89)(cid:72)(cid:85)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:40)(cid:37)(cid:44)(cid:55)(cid:39)(cid:36)(cid:3)(cid:87)(cid:82)(cid:3)(cid:73)(cid:85)(cid:72)(cid:72)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:372)(cid:82)(cid:90)(cid:17)
1 Non-GAAP Financial Measures and Forward Looking Statements
(cid:55)(cid:75)(cid:76)(cid:86)(cid:3)(cid:79)(cid:72)(cid:87)(cid:87)(cid:72)(cid:85)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:85)(cid:72)(cid:73)(cid:72)(cid:85)(cid:72)(cid:81)(cid:70)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:40)(cid:37)(cid:44)(cid:55)(cid:39)(cid:36)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:41)(cid:85)(cid:72)(cid:72)(cid:3)(cid:38)(cid:68)(cid:86)(cid:75)(cid:3)(cid:41)(cid:79)(cid:82)(cid:90)(cid:3)(cid:69)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)(cid:3)(cid:42)(cid:85)(cid:82)(cid:90)(cid:87)(cid:75)(cid:15)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)
measures. For reconciliations between our non-GAAP measures and the nearest GAAP measures, please refer to page 6 of
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(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:15)(cid:3)(cid:92)(cid:82)(cid:88)(cid:3)(cid:86)(cid:75)(cid:82)(cid:88)(cid:79)(cid:71)(cid:3)(cid:70)(cid:68)(cid:85)(cid:72)(cid:73)(cid:88)(cid:79)(cid:79)(cid:92)(cid:3)(cid:85)(cid:72)(cid:68)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:41)(cid:82)(cid:85)(cid:80)(cid:3)(cid:20)(cid:19)(cid:16)(cid:46)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:15)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)
(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:83)(cid:68)(cid:85)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:85)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:42)(cid:36)(cid:36)(cid:51)(cid:17)(cid:3)(cid:36)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:79)(cid:92)(cid:15)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:79)(cid:72)(cid:87)(cid:87)(cid:72)(cid:85)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:15)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:72)(cid:91)(cid:87)(cid:72)(cid:81)(cid:87)(cid:3)(cid:87)(cid:75)(cid:72)(cid:92)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)
recitations of historical fact, constitute forward-looking statements within the meaning of the federal securities laws, and are based
(cid:82)(cid:81)(cid:3)(cid:57)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:333)(cid:86)(cid:3)(cid:70)(cid:88)(cid:85)(cid:85)(cid:72)(cid:81)(cid:87)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:70)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:86)(cid:86)(cid:88)(cid:80)(cid:83)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:3)(cid:41)(cid:82)(cid:85)(cid:3)(cid:68)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:76)(cid:73)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:76)(cid:80)(cid:83)(cid:82)(cid:85)(cid:87)(cid:68)(cid:81)(cid:87)(cid:3)(cid:73)(cid:68)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:70)(cid:82)(cid:88)(cid:79)(cid:71)(cid:3)(cid:70)(cid:68)(cid:88)(cid:86)(cid:72)(cid:3)(cid:68)(cid:70)(cid:87)(cid:88)(cid:68)(cid:79)(cid:3)
(cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:89)(cid:68)(cid:85)(cid:92)(cid:3)(cid:80)(cid:68)(cid:87)(cid:72)(cid:85)(cid:76)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:87)(cid:75)(cid:82)(cid:86)(cid:72)(cid:3)(cid:68)(cid:81)(cid:87)(cid:76)(cid:70)(cid:76)(cid:83)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:73)(cid:82)(cid:85)(cid:90)(cid:68)(cid:85)(cid:71)(cid:16)(cid:79)(cid:82)(cid:82)(cid:78)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:57)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:333)(cid:86)(cid:3)(cid:403)(cid:79)(cid:76)(cid:81)(cid:74)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:40)(cid:38)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)
(cid:69)(cid:88)(cid:87)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:79)(cid:76)(cid:80)(cid:76)(cid:87)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:15)(cid:3)(cid:335)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:333)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:336)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:335)(cid:53)(cid:76)(cid:86)(cid:78)(cid:3)(cid:41)(cid:68)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:336)(cid:3)(cid:76)(cid:81)(cid:3)
(cid:87)(cid:75)(cid:72)(cid:3)(cid:41)(cid:82)(cid:85)(cid:80)(cid:3)(cid:20)(cid:19)(cid:16)(cid:46)(cid:3)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:17)
5
Non-GAAP Reconciliations — Adjusted EBITDA
Year Ended December 31, 2019 (Unaudited) (Millions of Dollars)
Retail
Ercot
PJM
NY/NE MISO
Eliminations/
Corp and
Other
Ongoing
Operations
Consolidated
Asset
Closure
Vistra Energy
Consolidated
Net income (loss)
$
134 $
1,368 $
405 $
188 $
55 $
(1,115) $
1,035
$
(109) $
Income tax expense
Interest expense and related
charges (a)
—
21
—
(8)
—
10
—
3
292
581
537
208
447
1,941
952
399
—
4
19
78
290
767
76
18
290
797
1,713
—
—
—
3,835
(cid:11)(cid:20)(cid:19)(cid:28)(cid:12)
278
(591)
(203)
(109)
(30)
(41)
(696)
—
23
—
—
49
10
—
(3)
—
—
11
12
—
(2)
—
—
6
7
—
4
—
—
4
9
12
15
—
—
21
7
—
42
(3)
—
—
—
2
12
33
37
48
115
9
—
(4)
37
48
24
(36)
46 $
3,393 $
(68) $
3,325
Depreciation and
amortization (b)
EBITDA before
Adjustments
Unrealized net (gain) or
loss resulting from hedging
transactions
Generation plant retirement
expenses
Fresh start / purchase
accounting impacts
Impacts of Tax Receivable
Agreement
Non-cash compensation
expenses
Transition and merger
expenses
Other, net
926
290
797
1,713
3,726
(696)
54
30
37
48
115
11
Adjusted EBITDA
$
807 $
1,370 $
760 $
307 $
103 $
(b) Includes nuclear fuel amortization of $73 million in the ERCOT segment.
Non-GAAP Reconciliations — Adjusted Free Cash Flow
Year Ended December 31, 2019 (Unaudited) (Millions of Dollars)
Adjusted EBITDA
Interest paid, net (a)
Taxes received net of payments
Severance
Working capital and margin deposits
Reclamation and remediation
Transition and merger expense
Changes in other operating assets and liabilities
Cash provided by operating activities
Capital expenditures including LTSA prepayments and nuclear fuel purchases (b)
Development and growth expenditures
Ambit and Crius acquisitions
Purchases and sales of environmental credits and allowances, net
Other net investing activities (c)
Free cash flow
Working capital and margin deposits
Development and growth expenditures
Severance
Ambit and Crius acquisitions
Purchases and sales of environmental credits and allowances, net
Transition and merger expense
Transition capital expenditures
Adjusted free cash flow before growth
Ongoing
Operations
Asset Closure
Vistra Energy
Consolidated
$
3,393
$
(68)
$
(500)
76
(7)
35
(15)
(116)
60
—
—
(10)
(17)
(101)
—
6
$
2,926
$
(190)
$
(609)
(104)
(880)
(125)
(4)
—
—
—
—
5
$
1,204
$
(185)
$
(35)
104
7
880
125
116
36
16
—
10
—
—
—
—
3,325
(500)
76
(17)
18
(116)
(116)
66
2,736
(609)
(104)
(880)
(125)
1
1,019
(19)
104
17
880
125
116
36
$
2,437
$
(159)
$
2,278
(a) Net of interest received.
(b) Includes $122 million LTSA prepaid capital expenditures.
(cid:11)(cid:70)(cid:12)(cid:3)(cid:44)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:72)(cid:71)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:81)(cid:88)(cid:70)(cid:79)(cid:72)(cid:68)(cid:85)(cid:3)(cid:71)(cid:72)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:85)(cid:88)(cid:86)(cid:87)(cid:3)(cid:73)(cid:88)(cid:81)(cid:71)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:372)(cid:82)(cid:90)(cid:86)(cid:17)
6
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, 2019
— OR —
☐ TRANSITION 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 Energy Corp.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
36-4833255
(I.R.S. Employer Identification No.)
6555 Sierra Drive
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 Rule 405 of the Securities Act. Yes ☒ No ☐
Indicated by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been
subject to such filing requirements for the past 90 days. Yes ☒ No ☐
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.
Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
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 28, 2019, the aggregate market value of the Vistra Energy Corp. common stock held by non-affiliates of the registrant was
$8,654,325,784 based on the closing sale price as reported on the New York Stock Exchange.
As of February 24, 2020, there were 487,734,006 shares of common stock, par value $0.01, outstanding of Vistra Energy Corp.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the registrant's 2020 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 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
SELECTED FINANCIAL DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
PART III.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
PRINCIPAL ACCOUNANT FEES AND SERVICES
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY
PART IV.
ii
1
17
38
39
41
41
42
44
45
72
78
170
171
173
173
173
173
173
173
174
184
185
Vistra Energy Corp.'s (Vistra Energy) annual reports, quarterly reports, current reports and any amendments to those reports are made
available to the public, free of charge, on the Vistra Energy website at http://www.vistraenergy.com, as soon as reasonably practicable after
they have been filed with or furnished to the Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended. Additionally, Vistra Energy posts important information, including press releases, investor presentations,
sustainability reports, and notices of upcoming events on its website and utilizes its website as a channel of distribution to reach public
investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD.
Investors may be notified of posting to the website by signing up for email alerts and RSS feeds on the "Investor Relations" page of Vistra
Energy's website. The information on Vistra Energy's website shall not be deemed a part of, or incorporated by reference into, this annual
report on Form 10-K. The representations and warranties contained in any agreement that we have filed as an exhibit to this annual report on
Form 10-K, or that we have or may publicly file in the future, may contain representations and warranties that may (i) be made by and to the
parties thereto at specific dates, (ii) be subject to exceptions and qualifications contained in separate disclosure schedules, (iii) represent the
parties' risk allocation in the particular transaction, or (iv) be qualified by materiality standards that differ from what may be viewed as
material for securities law purposes.
This annual report on Form 10-K and other Securities and Exchange Commission filings of Vistra Energy and its subsidiaries occasionally
make references to Vistra Energy (or "we," "our," "us" or "the Company"), Luminant, TXU Energy, Ambit Energy, Value Based Brands
LLC, 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 Energy 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 following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
GLOSSARY
2018 Form 10-K
Ambit
ARO
CAA
CAISO
CCGT
CFTC
Chapter 11 Cases
CME
CO2
CPUC
Crius
CT
Dynegy
Dynegy Energy Services
EBITDA
Effective Date
Emergence
EPA
Exchange Act
ERCOT
ESS
FERC
Fitch
FTC
GAAP
GHG
GWh
Vistra Energy's annual report on Form 10-K for the year ended December 31, 2018, filed
with the SEC on February 28, 2019, except for Exhibits 31.1, 31.2, 32.1 and 32.2, which
were amended in Vistra Energy's annual report on Form 10-K/A filed with the SEC on July
19, 2019
Ambit Holdings, LLC, and/or its subsidiaries, depending on context
asset retirement and mining reclamation obligation
Clean Air Act
The California Independent System Operator
combined cycle gas turbine
U.S. Commodity Futures Trading Commission
Cases in the U.S. Bankruptcy Court for the District of Delaware (Bankruptcy Court)
concerning voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code
(Bankruptcy Code) filed on April 29, 2014 (Petition Date) by Energy Future Holdings
Corp. (EFH Corp.) and the majority of its direct and indirect subsidiaries, including Energy
Future Intermediate Holding Company LLC, Energy Future Competitive Holdings
Company LLC and TCEH but excluding the Oncor Ring-Fenced Entities (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 Energy on
that date (Contributed EFH Debtors) emerged from the Chapter 11 Cases.
Chicago Mercantile Exchange
carbon dioxide
California 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 (d/b/a Dynegy
and Brighten Energy), indirect, wholly owned subsidiaries of Vistra Energy, that are REPs
in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of
electricity to residential and business customers.
earnings (net income) before interest expense, income taxes, depreciation and amortization
October 3, 2016, the date the TCEH Debtors and the Contributed EFH Debtors completed
their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases
emergence of the TCEH Debtors and the Contributed EFH Debtors from the Chapter 11
Cases as subsidiaries of a newly formed company, Vistra Energy, on the Effective Date
U.S. Environmental Protection Agency
Exchange Act of 1934, as amended
Electric Reliability Council of Texas, Inc.
energy storage system
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 Energy, a REP in certain areas of MISO that is engaged in the retail
sale of electricity to municipal customers
ICE
IRS
ISO
Intercontinental Exchange
U.S. Internal Revenue Service
independent system operator
ii
ISO-NE
kW
LIBOR
load
LTSA
Luminant
market heat rate
Merger
Merger Agreement
Merger Date
MISO
MMBtu
Moody's
MSHA
MW
MWh
NERC
NOX
NRC
NYMEX
NYSE
NYISO
Oncor
Oncor Ring-Fenced Entities
OPEB
Parent
PJM
Independent System Operator New England
kilowatt
London Interbank Offered Rate, an interest rate at which banks can borrow funds, in
marketable size, from other banks in the London interbank market
demand for electricity
long-term service agreements for plant maintenance
subsidiaries of Vistra Energy engaged in competitive market activities consisting of
electricity generation and wholesale energy sales and purchases as well as commodity risk
management
Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market
heat rate is the implied relationship between wholesale electricity prices and natural gas
prices and is calculated by dividing the wholesale market price of electricity, which is
based on the price offer of the marginal supplier (generally natural gas plants), by the
market price of natural gas.
the merger of Dynegy with and into Vistra Energy, with Vistra Energy as the surviving
corporation
the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra
Energy and Dynegy
April 9, 2018, the date Vistra Energy and Dynegy completed the transactions contemplated
by the Merger Agreement
Midcontinent Independent System Operator, Inc.
million British thermal units
Moody's Investors Service, Inc. (a credit rating agency)
U.S. Mine Safety and Health Administration
megawatts
megawatt-hours
North American Electric Reliability Corporation
nitrogen oxide
U.S. Nuclear Regulatory Commission
the New York Mercantile Exchange, a commodity derivatives exchange
New York Stock Exchange
New York Independent System Operator
Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor
Holdings and formerly an indirect subsidiary of EFH Corp., that is engaged in regulated
electricity transmission and distribution activities
Oncor Electric Delivery Holdings Company LLC and its direct and indirect subsidiaries,
including Oncor
postretirement employee benefits other than pensions
Vistra Energy Corp.
PJM Interconnection, LLC
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
Public Power
PUCT
PURA
REP
as part of the Spin-Off, the contribution of certain of the assets of the Predecessor and its
subsidiaries by a subsidiary of TEX Energy LLC to PrefCo in exchange for all of PrefCo's
authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
Public Power, LLC, an indirect, wholly owned subsidiary of Vistra Energy, a REP in
certain areas of PJM, NYISO, ISO-NE and MISO that is engaged in the retail sale of
electricity to residential and business customers
Public Utility Commission of Texas
Texas Public Utility Regulatory Act
retail electric provider
iii
RCT
RTO
S&P
SEC
Securities Act
SG&A
SO2
Spin-Off
ST
Tax Matters Agreement
TCJA
TCEH or Predecessor
Railroad Commission of Texas, which among other things, has oversight of lignite mining
activity in Texas
regional transmission organization
Standard & Poor's Ratings (a credit rating agency)
U.S. Securities and Exchange Commission
Securities Act of 1933, as amended
selling, general and administrative
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 applicable to business entities
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 major subsidiaries included Luminant and
TXU Energy
TCEH Debtors
the subsidiaries of TCEH that were Debtors in the Chapter 11 Cases
TCEQ
TRA
TRE
TXU Energy
TriEagle Energy
TWh
U.S.
U.S. Gas & Electric
Value Based Brands
Vistra Energy or Successor
Vistra Intermediate
Vistra Operations
Texas Commission on Environmental Quality
Tax Receivables Agreement, containing certain rights (TRA Rights) to receive payments
from Vistra Energy 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 reliability
standards for the ERCOT region and monitors and enforces compliance with NERC
standards and monitors compliance with ERCOT protocols
TXU Energy Retail Company LLC, an indirect, wholly owned subsidiary of Vistra Energy
that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity
to residential and business customers
TriEagle Energy, LP, an indirect, wholly owned subsidiary of Vistra Energy, 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
United States of America
U.S. Gas and Electric, Inc., an indirect, wholly owned subsidiary of Vistra Energy, a REP
in certain areas of PJM, NYISO, ISO-NE 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 and Express Energy), an indirect, wholly
owned subsidiary of Vistra Energy that is a REP in competitive areas of ERCOT and is
engaged in the retail sale of electricity to residential and business customers
Vistra Energy Corp., formerly known as TCEH Corp., and/or its subsidiaries, depending on
context. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors
emerged from Chapter 11 and became subsidiaries of Vistra Energy Corp.
Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra Energy
Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra Energy
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 Operations Company LLC's $5.425 billion senior secured financing facilities (see
Note 11 to the Financial Statements)
iv
Item 1. BUSINESS
PART I
References in this report to "we," "our," "us" and "the Company" are to Vistra Energy and/or its subsidiaries, as apparent
in the context. See Glossary for defined terms.
Business
Vistra Energy is a holding company operating an integrated retail and generation business primarily in markets throughout
the U.S. Through our subsidiaries, we are engaged in competitive energy activities including electricity generation, wholesale
energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users. We
incorporated under Delaware General Corporate Law in 2016.
We serve approximately 4.6 million customers and operate in 20 states and the District of Columbia. Our generation fleet
totals approximately 38,500 MW of generation capacity with a portfolio of natural gas, nuclear, coal, solar and battery energy
storage facilities.
Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-
NE), (v) MISO and (vi) Asset Closure. See Note 20 to the Financial Statements for further information concerning reportable
business segments.
As of December 31, 2019, we had approximately 5,475 full-time employees, including approximately 1,690 employees
under collective bargaining agreements.
Acquisitions and Merger
Ambit Transaction — On November 1, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the
acquisition of Ambit (Ambit Transaction). Because the Ambit Transaction closed on November 1, 2019, Vistra Energy's
consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of
Ambit and its subsidiaries prior to November 1, 2019. See Note 2 to the Financial Statements for a summary of the Ambit
Transaction.
Crius Transaction — On July 15, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the acquisition
of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius
Transaction). Because the Crius Transaction closed on July 15, 2019, Vistra Energy's consolidated financial statements and the
notes related thereto do not include the financial condition or the operating results of Crius and its subsidiaries prior to July 15,
2019. See Note 2 to the Financial Statements for a summary of the Crius Transaction.
Dynegy Merger Transaction — On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated
by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra
Energy continuing as the surviving corporation. Because the Merger closed on April 9, 2018, Vistra Energy's consolidated
financial statements and the notes related thereto do not include the financial condition or the operating results of Dynegy prior
to April 9, 2018. See Note 2 to the Financial Statements for a summary of the Merger transaction.
Business Strategy
Our business strategy is to deliver long-term stakeholder value through a focus on the following areas:
•
Integrated business model. We believe the key factor that distinguishes us from others in the competitive electricity
industry is the integrated nature of our business (i.e., pairing our reliable and efficient mining, diversified generation
fleet and wholesale commodity risk management capabilities with our retail platform). Our business strategy is
guided by our integrated business model because we believe it is our core competitive advantage and differentiates us
from our non-integrated competitors by reducing the effects of commodity price movements and contributing to
earnings and cash flow stability. Consequently, our integrated business model is at the core of our business strategy.
1
•
•
•
•
Disciplined capital allocation. Vistra Energy takes a balanced approach to capital allocation, focusing on
maintaining a strong balance sheet, investing prudently in the maintenance of our existing assets and potential growth
acquisitions, and returning capital to stockholders. A strong balance sheet helps to ensure Vistra Energy's interest
expense is manageable in a variety of wholesale power price environments while giving Vistra Energy access to
flexible and diverse sources of liquidity. We prudently make necessary capital investments to maintain the safety and
reliability of our facilities while also investing in new technologies when economic, including solar assets and battery
storage systems, resulting in a continued modernization of Vistra Energy's generation fleet. Because we believe cost
discipline and strong management of our assets and commodity positions are necessary to deliver long-term value to
our stakeholders, we generally make capital allocation decisions that we believe will lead to attractive cash returns on
investment, including by returning capital to our stockholders through quarterly dividends and our share repurchase
program (see Note 14 to the Financial Statements).
Superior customer service. Through TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services,
Homefield Energy, TriEagle Energy, Public Power and US Gas & Electric, we serve the retail electricity and natural
gas needs of end-use residential, small business, commercial and industrial electricity customers through multiple
sales and marketing channels. In addition to benefitting from our integrated business model, we leverage our brands,
our commitment to a consistent and reliable product offering, the backstop of the electricity generated by our
generation fleet, our wholesale commodity risk management operations and our strong customer service to
differentiate our products and services from our competitors. We strive to be at the forefront of innovation with new
offerings and customer experiences to reinforce our value proposition. We maintain a focus on solutions that give
our customers choice, convenience and control over how and when they use electricity and related services, including
TXU Energy's Free Nights and Solar Days residential plans, MyEnergy DashboardSM, TXU Energy's iThermostat
product and mobile solution, the TXU Energy Rewards program, the TXU Energy Green UpSM renewable energy
credit program and a diverse set of solar options. Our focus on superior customer service will guide our efforts to
acquire new residential and commercial customers, serve and retain existing customers and maintain valuable sales
channels for our electricity generation resources. We believe our customer service, products and trusted 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.
Excellence in operations while maintaining an efficient cost structure. We believe that operating our facilities in a
safe, reliable, environmentally compliant, and cost-effective and efficient manner is a foundation for delivering long-
term stakeholder value. We also believe value increases as a function of making disciplined investments that enable
our generation facilities to operate not only effectively and efficiently, but also safely, reliably and in an
environmentally compliant manner. We believe that an ongoing focus on operational excellence and safety is a key
component to success in a highly competitive environment and is part of the unique value proposition of our
integrated model. Additionally, we are committed to optimizing our cost structure, reducing our debt levels and
implementing enterprise-wide process and operating improvements without compromising the safety of our
communities, customers and employees. We believe we have a highly effective and efficient cost structure and that
our cost structure supports excellence in our operations.
Integrated hedging and commercial management. Our commercial team is focused on managing risk, through
opportunistic hedging, and optimizing our assets and business positions. We actively manage our exposure to
wholesale electricity prices in markets in which we operate, on an integrated basis, through contracts for physical
delivery of electricity, exchange-traded and over-the-counter financial contracts, term, day-ahead and real-time
including other power
market
generators and end-user electricity customers. We seek to hedge near-term cash flow and optimize long term value
through hedging and forward sales contracts. We believe our integrated hedging and commercial management
strategy, in combination with a strong balance sheet and strong liquidity profile, will provide a long-term advantage
through cycles of higher and lower commodity prices.
transactions, and bilateral contracts with other wholesale market participants,
2
•
•
fuel
technologies,
Growth and enhancement. Our growth strategy leverages our core capabilities of multi-channel retail marketing in
large and competitive markets, operating large-scale, environmentally sensitive, and diverse assets across a variety of
fuel
logistics and management, commodity risk management, cost control, and energy
infrastructure investing. We intend to opportunistically evaluate the acquisition and development of high-quality
energy infrastructure assets and businesses, including renewable energy and battery storage assets as well as retail
businesses, that complement these core capabilities and enable us to achieve operational or financial synergies.
While we are intent on growing our business and creating value for our stockholders, we are committed to making
disciplined investments that are consistent with our focus on maintaining a strong balance sheet and strong liquidity
profile. As a result, consistent with our disciplined capital allocation approval process, growth opportunities we
pursue will need to have compelling economic value in addition to fitting with our business strategy.
Corporate responsibility and citizenship. We are committed to providing safe, reliable, cost-effective and
environmentally compliant electricity for the communities and customers we serve. We strive to improve the quality
of life in the communities in which we operate. We are also committed to being a good corporate citizen in the
communities in which we conduct operations. We and our employees are actively engaged in programs intended to
support and strengthen the communities in which we conduct operations. Our foremost giving initiatives are through
the United Way, 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.
Recent Developments
Dividend Declaration — In February 2020, the Board declared a quarterly dividend of $0.135 per share that will be paid
in March 2020.
Market Discussion
The operations of Vistra Energy are aligned into six reportable business segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv)
NY/NE, (v) MISO and (vi) Asset Closure. The Retail segment is engaged in retail sales of electricity and natural gas to
residential, commercial and industrial customers. The ERCOT, PJM, NY/NE (comprising NYISO and ISO-NE) and MISO
segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities,
fuel production and fuel logistics management, all largely within their respective RTO or ISO market. The Asset Closure
segment is engaged in the decommissioning and reclamation of retired plants and mines. Our CAISO operations are included
in the Corporate and Other non-segment as our operations in the CAISO market do not materially affect our financial condition,
results of operations and cash flows. See Note 20 to the Financial Statements for additional information related to our operating
segments.
Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)
Separately, RTOs and ISOs administer the transmission infrastructure and markets across a regional footprint in most of
the markets in which we operate. They are responsible for dispatching all generation facilities in their respective footprints and
are responsible for both maximum utilization and reliable and efficient operation of the transmission system. RTOs and ISOs
administer energy and ancillary service markets in the short term, usually day-ahead and real-time markets. Several RTOs and
ISOs also ensure long-term planning reserves through monthly, semiannual, annual and multiyear capacity markets. The RTOs
and ISOs that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to
impose, bid and price limits or other similar mechanisms. NERC regions and RTOs/ISOs often have different geographic
footprints, and while there may be geographic overlap between NERC regions and RTOs/ISOs, their respective roles and
responsibilities do not generally overlap.
3
In RTO and ISO regions with centrally dispatched market structures, all generators selling into the centralized market
receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to
balance supply with demand within a designated zone or at a given location. Different zones or locations within the same RTO/
ISO may produce different prices respective to other zones within the same RTO/ISO due to transmission losses and
congestion. For example, a less efficient and/or less economical natural gas-fueled unit may be needed in some hours to meet
demand. If this unit's production is required to meet demand on the margin, its offer price will set the market clearing price that
will be paid for all dispatched generation in the same zone or location (although the price paid at other zones or locations may
vary because of transmission losses and congestion), regardless of the price that any other unit may have offered into the
market.
In RTO and ISO regions with centrally dispatched market structures and location-based marginal price clearing
structures (e.g. PJM, ISO-NE, NYISO, ERCOT, MISO, and CAISO), generators will receive the location-based marginal price
for their output. The location-based marginal price, absent congestion, would be the marginal price of the most expensive unit
In regions that are outside the footprint of RTOs/ISOs, prices are determined on a bilateral basis
needed to meet demand.
between buyers and sellers.
Retail Markets
The Retail segment is engaged in retail sales of electricity, natural gas and related services to approximately 4.6 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 US Gas & Electric across 19 U.S. states and the
District of Columbia.
The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 2.3 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, having one of the lowest
customer complaint rates according to the PUCT. As of December 31, 2019, we provided electricity to approximately 31% of
the residential customers in ERCOT and for more than 10% of business customers' demand. We believe that we have
differentiated ourselves by providing a distinctive customer experience predicated on delivering reliable and innovative power
products and solutions to our customers, 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
consumption 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 enables 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 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.
Outside of ERCOT, we also serve residential, municipal, commercial and industrial customers substantially through our
Homefield Energy, Dynegy Energy Services, Public Power, US Gas & Electric and Ambit Energy retail businesses, through
which we provide retail electricity, natural gas and related services to approximately 2.3 million customers in 18 states and the
District of Columbia.
4
ERCOT Market
ERCOT is an ISO that manages the flow of electricity from approximately 82,000 MW of installed generation capacity 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 from other competitive electricity markets in the U.S.
Other markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/
In contrast, ERCOT's resource adequacy is predominately dependent on energy-market price signals.
or capacity markets.
ERCOT implemented the Operating Reserve Demand Curve (ORDC), pursuant to which wholesale electricity prices in the real-
time electricity market increase automatically as available operating reserves decrease below defined threshold levels, creating
a price adder. When operating reserves drop to 2,000 MW or less, the ORDC automatically adjusts power prices to the
established value of lost load (VOLL), which is set at $9,000/MWh. In 2019, ERCOT implemented a .25 standard deviation
shift in the loss of load probability calculation using a single blended ORDC curve; these changes resulted in a more rapid
escalation in power prices as operating reserves fall below defined thresholds. Subsequently, in 2020 ERCOT will implement
an additional .25 standard deviation shift in the loss of load probability calculation, which is expected to result in a steeper price
escalation during scarcity events in 2020 relative to 2019. Because ERCOT has limited excess generation capacity to meet high
demand days due to its minimal import capacity, and peaking facilities have high operating costs, the marginal price of supply
rapidly increases during periods of high demand. Historically, elevated temperatures in the summer months have driven high
electricity demand in ERCOT. Many generators benefit from these sporadic periods of "scarcity pricing" in which power prices
may increase significantly, up to the current $9,000/MWh price cap. Other than during periods of "scarcity pricing," the price
of power is typically set by natural gas-fueled generation facilities; as a result, historically low natural gas prices have had a
corresponding impact on wholesale prices (see Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations – Key Operational Risks and Challenges).
Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market. The day-ahead
market is a voluntary, forward electricity market conducted the day before each operating day in which generators and
purchasers of electricity may bid for one or more hours of electricity supply or consumption. The real-time market is a spot
market in which electricity may be sold in five-minute intervals. The day-ahead market provides market participants with
visibility into where prices are expected to clear, and the prices are not impacted by subsequent events. Conversely, the real-
time market exposes purchasers to the risk of transient operational events and price spikes. These two markets allow market
participants to manage their risk profile by adjusting their participation in each market.
In addition, ERCOT uses ancillary
services to maintain system reliability, including regulation service-up, regulation service-down, responsive reserve service and
non-spinning reserve service. Regulation service up and down are used to balance the grid in a near-instantaneous fashion
when supply and demand fluctuate due to a variety of factors, such as weather, generation outages, renewable production
intermittency and transmission outages. Responsive reserves and non-spinning reserves are used by ERCOT when the grid is
at, near or recovering from a state of emergency due to inadequate generation. Because ERCOT has one of the highest
concentrations of wind capacity generation among U.S. markets, the ERCOT market is more susceptible to fluctuations in
wholesale electricity supply due to intermittent wind production, making ERCOT more vulnerable to periods of generation
scarcity.
Our ERCOT segment is comprised of 20 power generation facilities located in Texas totaling 18,356 MW of generation
capacity. Our ERCOT fleet includes seven CCGT natural gas-fueled generation facilities totaling 7,838 MW, three lignite/coal-
fueled generation facilities totaling 4,500 MW, eight natural gas-fueled peaking generation facilities totaling 3,538 MW, a
nuclear generation facility totaling 2,300 MW and a solar photovoltaic power generation facility totaling 180 MW. We also
operate a 10 MW battery energy storage system (ESS) at our Upton 2 solar facility.
PJM Market
PJM is an RTO that manages the flow of electricity from approximately 180,000 MW of installed generation capacity to
approximately 65 million customers in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey,
North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
5
PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing a locational
marginal pricing (LMP) methodology which calculates a price for every generator and load point within PJM. This market is
transparent, allowing generators and load serving entities to see real-time price effects, transmission constraints and the impacts
of congestion at each pricing point. PJM operates day-ahead and real-time markets into which generators can bid to provide
energy and ancillary services. PJM also administers a forward capacity auction, the Reliability Pricing Model (RPM), which
establishes long-term markets for capacity. We have participated in RPM auctions for years up to and including PJM's planning
year 2021-2022, which ends May 31, 2022. We also enter into bilateral capacity transactions. PJM's Capacity Performance
(CP) rules are designed to improve system reliability and include penalties for under-performing units and reward for over-
performing units during shortage events. PJM's base capacity resources are those capacity resources not capable of sustained,
predictable operation throughout the entire delivery year, but can provide energy and reserves during hot weather operations.
The base capacity resources are subject to non-performance charges assessed during emergency conditions from June through
September. Full transition of the capacity market to CP rules will occur by planning year 2020-2021. An independent market
monitor continually monitors PJM markets to ensure a robust, competitive market and to identify improper behavior by any
entity.
Our PJM segment is comprised of 17 power generation facilities totaling 10,769 MW of generating capacity. Our PJM
fleet includes eight CCGT natural gas-fueled generation facilities totaling 5,902 MW, three coal-fueled generation facilities
totaling 3,428 MW, four natural gas-fueled generation facilities totaling 1,346 MW and two oil-fueled generation facilities
totaling 93 MW. Of these facilities, eight are located in Ohio, three in Pennsylvania, three in Illinois and one each in New
Jersey, Virginia and West Virginia.
NYISO and ISO-NE Markets
NYISO is an ISO that manages the flow of electricity from approximately 39,000 MW of installed generation capacity to
approximately 20 million New York customers.
The NYISO market dispatches power plants to meet system energy and reliability needs and settles physical power
deliveries at LMPs. Energy prices vary among the regional zones in the NYISO and are largely influenced by transmission
constraints and fuel supply. NYISO offers a forward capacity market where capacity prices are determined through auctions.
Strip auctions occur one to two months prior to the commencement of a six-month seasonal planning period. Subsequent
auctions provide an opportunity to sell excess capacity for the balance of the seasonal planning period or the upcoming month.
Due to the short-term nature of the NYISO-operated capacity auctions and a relatively liquid bilateral market for NYISO
capacity products, our Independence facility sells a significant portion of its capacity through bilateral transactions. The
balance is cleared through the seasonal and monthly capacity auctions.
ISO-NE is an ISO that manages the flow of electricity from approximately 31,000 MW of installed generation capacity to
approximately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island and
Maine.
ISO-NE dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at
LMPs. Energy prices vary among the participating states in ISO-NE and are largely influenced by transmission constraints and
fuel supply.
ISO-NE offers a forward capacity market where capacity prices are determined through auctions. Performance
incentive rules have the potential to increase capacity payments for those resources that are providing excess energy or reserves
during a shortage event, while penalizing those that produce less than the required level.
Our NY/NE segment is comprised of eight CCGT natural gas-fueled generation facilities totaling 4,730 MW of generation
capacity. Of these facilities, four are located in Massachusetts, two in Connecticut and one each in Maine and New York.
MISO Market
MISO is an RTO that manages the flow of electricity from approximately 190,000 MW of installed generation capacity to
approximately 42 million customers in all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan, Kentucky, Indiana,
Illinois, Missouri, Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota and Manitoba, Canada.
6
The MISO energy market is designed to ensure that all market participants have open-access to the transmission system
on a non-discriminatory basis. MISO, as an independent RTO, maintains functional control over the use of the transmission
system to ensure transmission circuits do not exceed their secure operating limits and become overloaded. MISO operates day-
ahead and real-time energy markets using a similar LMP methodology as described above for the PJM market. An independent
market monitor is responsible for evaluating the performance of the markets and identifying conduct by market participants or
MISO that may compromise the efficiency or distort the outcome of the markets.
MISO administers a one-year Forward Capacity Auction for the next planning year from June 1st of the current year to
May 31st of the following year. We participate in these auctions with open capacity that has not been committed through
bilateral or retail transactions. We also participate in the MISO annual and monthly 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.
Our MISO segment is comprised of four power generation facilities located in Illinois totaling 3,408 MW of generation
capacity. Joppa, which is within the Electric Energy, Inc. (EEI) control area, is interconnected to Tennessee Valley Authority
and Louisville Gas and Electric Company, but primarily sells its capacity and energy to MISO. Edwards is scheduled to be
retired by the end of 2022 pursuant to the terms of a federal consent decree. We currently offer a portion of our MISO segment
generating capacity and energy into PJM. Our Edwards and Newton generation facilities have 1,200 MW electrically tied into
PJM through pseudo-tie arrangements. These pseudo-tie arrangements are scheduled to terminate on March 1, 2020, after
which time Edwards and Newton will offer their generating capacity and energy solely into MISO.
CAISO Market
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 utilizing an LMP methodology as described above. The capacity market is comprised of Generic,
Flexible and Local Resource Adequacy (RA) Capacity and is administered by the California Public Utilities Commission.
Unlike other centrally cleared capacity markets, the resource adequacy market in California is a bilaterally traded market. In
November 2016, CAISO implemented a voluntary capacity auction for annual, monthly, and intra-month procurement to cover
for deficiencies in the market. The voluntary Competitive Solicitation Process, which FERC approved in October 2015, is a
modification to the Capacity Procurement Mechanism (CPM) and provides another avenue to sell RA capacity.
Our CAISO operations are comprised of two power generation facilities located in California totaling 1,185 MW of
generating capacity. Our CAISO fleet includes one CCGT natural gas-fueled generation facility totaling 1,020 MW and one
oil-fueled generation facility totaling 165 MW. In 2018 and 2019, we announced the planned development of a 300 MW ESS
at our Moss Landing facility and a 20 MW ESS at our Oakland facility (see Note 3 to the Financial Statements).
Wholesale Operations
Our wholesale commodity risk management group is responsible for dispatching our generation fleet in response to
market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production
with our retail customer and wholesale sales opportunities. Market demand, also known as load, faced by electric power
systems, such as those we operate in, varies from moment to moment as a result of changes in business and residential demand,
which is often driven by weather. Unlike most other commodities, the production and consumption of electricity must remain
balanced on an instantaneous basis. There is a certain baseline demand for electricity across an electric power system that
occurs throughout the day, which is typically satisfied by baseload generating units with low variable operating costs. Baseload
generating units can also increase output to satisfy certain incremental demand and reduce output when demand is unusually
low.
Intermediate/load-following generating units, which can more efficiently change their output to satisfy increases in
demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in demand or
unexpected changes in supply created by reduced generation from renewable resources or other generator outages. Peak daily
loads may be satisfied by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up
and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load following units and peaking units
are dispatched into the RTO/ISO grid in order from lowest to highest variable cost. Price formation is typically based on the
highest variable cost unit that clears the market to satisfy system demand at a given point in time.
7
Our commodity risk management group also enters into electricity, gas and other commodity derivative contracts to
reduce exposure to changes in prices primarily to hedge future revenues and fuel costs for our generation facilities and
purchased power costs for our Retail segment.
Seasonality
The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results
may fluctuate on a seasonal basis. Typically, demand for and the price of electricity is higher in the summer and winter
seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the
winter. More severe weather conditions such as heat waves or extreme winter weather may make such fluctuations more
pronounced. However, not all regions of the U.S. typically experience extreme weather conditions at the same time, so Vistra
Energy is typically not exposed to the effects of extreme weather in all parts of its business at once. The pattern of this
fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell
electricity.
Competition
Competition in the markets in which we operate is impacted by electricity and fuel prices, congestion along the power
grid, subsidies provided by state and federal governments for new and existing generation facilities, new market entrants,
construction of new generating assets, technological advances in power generation, the actions of environmental and other
regulatory authorities, and other factors. We primarily compete with other electricity generators and retailers based on our
ability to generate 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 competitive energy markets in
which we operate.
Brand Value
Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in
Texas for approximately 18 years, is registered and protected by trademark law and is the only material intellectual property
asset that we own. We have also acquired the trade names for Ambit Energy, Dynegy Energy Services, Homefield Energy,
TriEagle Energy, Public Power and US Gas & Electric through the Ambit Transaction, Crius Transaction and the Merger. As
of December 31, 2019, we have reflected intangible assets on our balance sheet for our trade names of approximately $1.391
billion (see Note 6 to the Financial Statements).
Environmental Regulations and Related Considerations
We are subject
to extensive environmental regulation by governmental authorities,
including the EPA and the
environmental regulatory bodies of states in which we operate. The EPA has recently finalized or proposed several regulatory
actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities.
See Item 1A. Risk Factors for additional discussion of risks posed to us regarding regulatory requirements. See Note 13 to the
Financial Statements for a discussion of litigation related to EPA reviews.
Climate Change
There is attention and interest nationally and internationally about global climate change and how greenhouse gas (GHG)
emissions, such as carbon dioxide (CO2), contribute to global climate change. GHG emissions from the combustion of fossil
fuels, primarily by our coal/lignite-fueled-generation plants, represent the substantial majority of our total GHG emissions.
CO2, methane and nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG
emissions. We estimate that our generation facilities produced approximately 116 million short tons of CO2 in 2019.
We have already taken or announced significant steps to transition the fuel-mix and reduce the emissions profile of our
generation fleet, including:
•
Acquisition of CCGTs — In 2016 and 2017, we acquired 4,042 MW of CCGTs in Texas.
15,448 MW of CCGTs in connection with the Merger.
In 2018, we acquired
8
•
•
•
Retirement of Coal 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 585
MW of coal-fueled generation facilities in Illinois by the end of 2022.
Solar Development Project — In 2018, we began commercial operation of our 180 MW Upton 2 solar facility.
Battery Energy Storage Projects — In 2018, a 10 MW battery energy storage system (ESS) at our Upton 2 solar
In 2018 and 2019, we announced the planned development of a 300 MW ESS at our
facility became operational.
Moss Landing facility and a 20 MW ESS at our Oakland facility.
In 2019, we began construction of the Moss
Landing ESS.
See Note 4 to the Financial Statements for discussion of our retirement of generation facilities and Note 3 for discussion
of our solar and battery energy storage projects.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address GHG emissions from electricity generation units, referred to as the
Clean Power Plan, including rules for existing facilities that would establish state-specific emissions rate goals to reduce
nationwide CO2 emissions. Various parties filed petitions for review in the U.S. Court of Appeals for the District of Columbia
Circuit (D.C. Circuit Court). In July 2019, petitioners filed a joint motion to dismiss in light of the EPA's new rule that replaces
the Clean Power Plan, the Affordable Clean Energy rule, discussed below. In September 2019, the D.C. Circuit Court granted
petitioners' motion to dismiss and dismissed all of the petitions challenging the Clean Power Plan as moot.
In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with new regulations addressing GHG emissions
from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule
develops emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled
electric generating units. States must submit their plans for regulating GHG emissions from existing facilities by July 2022.
States where we operate coal plants (Texas, Illinois and Ohio) have begun the development of their state plans to comply with
the rule. Environmental groups and certain states filed petitions for review of the ACE rule and the repeal of the Clean Power
Plan in the D.C. Circuit Court. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards
for new, modified and reconstructed units. Vistra Energy submitted comments on that proposed rulemaking. While we cannot
predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, the
rules, if implemented, could have a material impact on our results of operations, liquidity or financial condition.
State Regulation of GHGs
Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only
regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change.
Regional Greenhouse Gas Initiative (RGGI) — RGGI is a state-driven GHG emission control program that took effect in
2009 and was initially implemented by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants.
The participating RGGI states implemented a cap-and-trade program. Compliance with RGGI can be achieved by reducing
emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. We are required to
hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period.
In December 2017, the RGGI states released an updated model rule with changes to the CO2 budget trading program,
including an additional 30 percent reduction in the CO2 annual cap by the year 2030, relative to 2020 levels. The RGGI cap on
CO2 emissions would decline by 2.275 million tons per year beginning in 2021. Each RGGI state will work to ensure that its
program changes are in effect by 2021.
Our generating facilities in Connecticut, Maine, Massachusetts and New York emitted approximately 7.8 million tons of
CO2 during 2019. The spot market price of RGGI allowances required to operate these facilities as of December 31, 2019 was
approximately $5.65 per allowance. The spot market price of RGGI allowances required to operate our affected facilities
during 2020 was $5.94 per allowance on February 24, 2020. While the cost of allowances required to operate our RGGI-
affected facilities is expected to increase in future years, we expect that the cost of compliance would be reflected in the power
market, and the actual impact to gross margin would be largely offset by an increase in revenue.
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Massachusetts — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final
rules establishing an annual declining limit on aggregate CO2 emissions from 21 in-state fossil-fueled electricity generation
units. The rules establish an allowance trading system under which the annual aggregate electricity generation unit sector cap
on CO2 emissions declines from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. MassDEP allocated
emission allowances to affected facilities for 2018. Beginning in 2019, the allocation process 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 established by the rule. Beginning in 2021, all allowances will be distributed through the
auction. Limited banking of unused allowances is allowed.
Virginia — In May 2019, the Virginia Department of Environmental Quality issued a final rule to adopt a carbon 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 rule and is intended to link Virginia to RGGI.
New Jersey — In January 2018, the Governor of New Jersey signed an executive order directing the state's environmental
agency and public utilities board to begin the process of rejoining RGGI, and New Jersey formally 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.
California — Our assets in California are subject to the California Global Warming Solutions Act, which required the
California Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state
to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establishing a new statewide GHG
reduction target of 40 percent below 1990 levels by 2030 to ensure California meets its 2050 GHG reduction target of 80
percent below 1990 levels. We have participated in quarterly auctions or in secondary markets, as appropriate, to secure
allowances for our affected assets.
In July 2017, California enacted legislation extending its GHG cap-and-trade program through 2030 and the CARB
adopted amendments to its cap-and-trade regulations that, among other things, established a framework for extending the
program beyond 2020 and linking the program to the new cap-and-trade program in Ontario, Canada beginning in January
2018.
Air Emissions
The Clean Air Act (CAA)
The CAA and comparable state laws and regulations relating to air emissions impose various responsibilities on owners
and operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit
fees, monitor emissions, submit reports and compliance certifications, and keep records. The CAA requires that fossil-fueled
electricity generation plants meet certain pollutant emission standards and have sufficient emission allowances to cover sulfur
dioxide (SO2) emissions and in some regions nitrogen oxide (NOX) emissions.
In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission
reduction technologies. These technologies include flue gas desulfurization (FGD) systems, dry sorbent injection (DSI),
baghouses and activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective
catalytic reduction (SCR) systems, low-NOX burners and/or overfire air systems on all units. Additionally, our MISO coal-
fueled facilities mainly use low sulfur coal, which, prior to combustion, goes through a refined coal process to further reduce
NOX and mercury emissions. In 2018, we received approval to use refined coal at some of our Texas coal-fueled facilities.
Cross-State Air Pollution Rule (CSAPR)
In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of
SO2 and NOX emissions from our fossil-fueled generation units. After certain EPA revisions to the rule, the CSAPR became
effective January 1, 2015. In October 2016, the EPA issued a CSAPR update, which revised the ozone season NOx limits for
22 eastern states, including Texas. Under the CSAPR, our generating facilities in Illinois, Ohio, New Jersey, New York,
Pennsylvania, Virginia, and West Virginia are subject to cap-and-trade programs for ozone-season emissions of NOx from May
1 through September 30 and for annual emissions for SO2 and NOX. Our generating facilities in Texas are subject to the
CSAPR NOx ozone season cap-and-trade program. While we cannot predict the outcome of future proceedings related to the
CSAPR, based upon our current operating plans, we do not believe that the CSAPR itself will cause any material operational,
financial or compliance issues to our business or require us to incur any material compliance costs.
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Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas
The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of
any existing, impairment of visibility in mandatory class I federal areas which impairment results from man-made pollution."
There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I
federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in
neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second,
certain electricity generation units built between 1962 and 1977 are subject to BART standards designed to improve visibility if
such units cause or contribute to impairment of visibility in a federal class I area. BART reductions of SO2 and NOX are
required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading
program such as the CSAPR or other approved alternative program.
In January 2016,
the EPA issued a final rule approving in part and disapproving in part Texas's 2009 State
Implementation Plan (SIP) as it relates to the reasonable progress component of the Regional Haze Program and issuing a
Federal Implementation Plan (FIP). The EPA's emission limits in the FIP assume additional control equipment for specific
lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity
generation units (including Big Brown Units 1 and 2, Monticello Units 1 and 2 and Coleto Creek) and upgrades to existing
scrubbers at seven generation units (including Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4).
In March 2016, various parties (including Luminant and the State of Texas) filed petitions for review in the U.S. Court of
Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the FIP's Texas requirements.
In July 2016, the Fifth Circuit
Court granted motions to stay the rule pending final review of the petitions for review. In March 2017, the Fifth Circuit Court
granted a motion by the EPA to remand the rule back to the EPA for reconsideration. The stay of the rule (and the emission
control requirements) remains in effect. The retirements of our Monticello, Big Brown and Sandow 4 plants should have a
favorable impact on this rulemaking and litigation. Further, we believe that these retirements and the BART rule (discussed
below) obviates the need for any additional limits on our remaining Texas plants to address the requirements in the regional
haze rule. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably
possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.
In September 2017, the EPA signed a final rule addressing BART for Texas electricity generation units, with the rule
serving as a partial approval of Texas's 2009 SIP and a partial FIP. For SO2, the rule creates an intrastate Texas emission
allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The
program includes 39 generating units (including our Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2
and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. We believe the retirements of
our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO2. For NOX, the
rule adopts the CSAPR's ozone program as BART and for particulate matter, the rule approves Texas's SIP that determines that
no electricity generation units are subject to BART for particulate matter. Various parties filed a petition challenging the rule in
the Fifth Circuit Court as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA
in the Fifth Circuit Court action.
In March 2018, the Fifth Circuit Court abated its proceedings until the EPA concludes the
reconsideration process. In August 2018, the EPA issued a proposal to affirm the prior BART final rule and seeking comments
In November 2019, the EPA proposed additional revisions to the BART
on that proposal, which were due in October 2018.
final rule, and we submitted comments on that proposal in January 2020. While we cannot predict the outcome of the
rulemaking and legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material
impact on our results of operations, liquidity or financial condition.
Affirmative Defenses During Malfunctions
In May 2015, the EPA finalized a rule requiring 36 states, including Texas, Illinois and Ohio, to remove or replace either
EPA-approved exemptions or affirmative defense provisions for excess emissions during upset events and unplanned
maintenance and startup and shutdown events, referred to as the SIP Call. Various parties (including Luminant, the State of
Texas and the State of Ohio) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the
D.C. Circuit Court.
In April 2019, the EPA
Region 6 proposed a rule to withdraw the SIP Call with respect to the Texas affirmative defense provisions. We submitted
comments on that proposed rulemaking in June 2019. In January 2020, the EPA took final action to withdraw the Texas SIP
Call. While we cannot predict the timing or outcome of the rulemaking and legal proceedings, we believe the rule, if ultimately
implemented or upheld as issued, will not have a material impact on our results of operations, liquidity or financial condition.
In April 2017, the D.C. Circuit Court ordered the case to be held in abeyance.
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National Ambient Air Quality Standards (NAAQS)
The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment.
The EPA has established NAAQS for six such pollutants, including SO2 and ozone. Each state is responsible for developing a
SIP that will attain and maintain the NAAQS. These plans may result in the imposition of emission limits on our facilities.
SO2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello
and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas.
In
February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court.
Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the
EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for
reconsideration to the EPA.
In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if
finalized, would revise its previous nonattainment designations and each area at issue would be designated unclassifiable. In
September 2019, we submitted comments in support of the proposed Error Correction Rule. While we cannot predict the
outcome of this matter, or estimate a range of reasonably possible costs, the result could have a material impact on our results of
operations, liquidity or financial condition.
Ozone Designations — The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per
billion. Various parties challenged the 2015 ozone NAAQS; however, in August 2019, the D.C. Circuit Court generally upheld
the 2015 ozone NAAQS but remanded the secondary ozone standard to the EPA for reconsideration. In November 2017, the
EPA issued an initial round of area designations for the 2015 ozone NAAQS, designating most areas of the U.S. as attainment/
unclassifiable. Several states and other groups have filed lawsuits seeking to compel the EPA to complete designations for all
In December 2017, the EPA notified states of expected nonattainment area designations for the 2015
areas of the country.
ozone NAAQS. Those areas include areas concerning our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet
facility in Illinois and our Wise, Ennis and Midlothian facilities in Texas. In June 2018, the EPA finalized these designations as
marginal nonattainment areas.
In November 2017, the EPA denied a petition from nine northeastern states to add several states, including Illinois and
Ohio, to the Ozone Transport Region. Eight of the northeastern states filed a petition for judicial review challenging the EPA's
action in the D.C. Circuit Court.
In April 2019, the D.C. Circuit Court denied the states' petition for review, upholding the
EPA's denial. Additionally, in January 2018, New York and Connecticut filed a lawsuit against the EPA in the Southern
District of New York seeking to compel the agency to issue a FIP for the 2008 ozone NAAQS that addresses sources in five
upwind states, including Illinois. The plaintiffs filed a motion for summary judgment on the matter in April 2018, and the court
granted that motion in June 2018. As a result, the EPA was required to propose an action to address the 2008 ozone NAAQS
In January 2019, the plaintiffs informed the district
by June 29, 2018, and promulgate a final action by December 6, 2018.
court that the EPA had satisfied its deadlines in accordance with the court's order. However, in January 2019, New York,
Connecticut, four other states, and the City of New York filed a separate petition for review in the D.C. Circuit Court
challenging the final action the EPA took in December 2018 consistent with the Southern District of New York's order.
In
October 2019, the D.C. Circuit Court vacated the final rule, and in January 2020, New York and Connecticut filed a lawsuit
against the EPA in the Southern District of New York to compel the EPA to comply with the court's June 2018 order.
In November 2016, the State of Maryland petitioned the EPA to impose additional NOX emission control requirements on
36 electricity generation units in five upwind states, including our Zimmer facility, that the State alleges are contributing to
nonattainment with the 2008 ozone NAAQS in Maryland. In the fall of 2017, Maryland and several environmental groups filed
lawsuits against the EPA seeking to compel the Agency to act on the State's petition.
In October 2018, the EPA took final
action denying the Maryland petition, and Maryland filed a petition for review of the EPA's denial in the D.C. Circuit Court.
While we cannot predict the outcome of the judicial proceedings, given that the Zimmer facility utilizes SCR technology to
control NOX emissions, we do not believe that the result of these proceedings could cause a material adverse impact on our
future financial results.
In March 2018, the State of New York petitioned the EPA to find that emissions from hundreds of sources in nine states,
including Illinois, Ohio, Virginia and West Virginia are significantly contributing to New York's nonattainment and interfering
with New York's maintenance of the 2008 and 2015 ozone NAAQS. On October 18, 2019, the EPA took final action denying
New York's petition. On October 29, 2019, New York, New Jersey and the City of New York filed a petition for review of the
EPA's denial of the Section 126 petition. Briefing in the D.C. Circuit Court is ongoing.
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Illinois Multi-Pollutant Standards (MPS)
In August 2019, changes proposed by the Illinois Pollution Control Board to the Illinois multi-pollutant standard rule
(MPS rule), which places NOx, SO2 and mercury emissions limits on our coal plants located in MISO went into effect. Under
the revised MPS rule, our allowable SO2 and NOx emissions from the MISO fleet are 48% and 42% lower, respectively, than
prior to the rule changes. The revised MPS rule requires the continuous operation of existing selective catalytic reduction
(SCR) control systems during the ozone season, requires SCR-controlled units to meet an ozone season NOx emission rate
limit, and set an additional, site-specific annual SO2 limit for our Joppa Power Station. Additionally, in 2019, the Company
retired its Havana, Hennepin, Coffeen and Duck Creek plants in order to comply with the MPS rule's requirement to retire at
least 2,000 MW of the company's generation in MISO. See Note 4 to the Financial Statements for information regarding the
retirement of the four plants.
CAA Matters
Zimmer NOVs — In December 2014, the EPA issued a notice of violation (NOV) alleging violation of opacity standards
at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the
Ohio State Implementation Plan and the station's air permits including standards applicable to opacity, sulfur dioxide, sulfuric
acid mist and heat input. In January 2020, the U.S. Department of Justice filed a complaint and proposed consent decree agreed
to by Dynegy Zimmer, LLC in the U.S. District Court for the Southern District of Ohio that would resolve claims alleged in the
2008, 2010 and 2014 NOVs. The court has not yet entered the consent decree as effective. We believe that if the consent
decree is entered by the court as proposed, it will not have a material impact on our results of operations, liquidity or financial
condition.
Edwards CAA Citizen Suit — In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for
the Central District of Illinois against one of our subsidiaries that owns the Edwards Power Plant alleging violations of opacity
and particulate matter limits at our MISO segment's Edwards facility. In August 2016, the district court granted the plaintiffs'
motion for summary judgment on certain liability issues. In September 2019, the parties to the lawsuit announced a proposed
settlement which was approved by the court in a consent decree in November 2019. The consent decree requires the retirement
of the Edwards plant by the end of 2022 and funding for certain projects that benefit Peoria-area communities. See Note 4 to
the Financial Statements for information regarding the expected retirement of the Edwards plant.
Coal Combustion Residuals (CCR)/Groundwater
The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at
power generation facilities in dry form in landfills and in wet form in surface impoundments. Each of our coal-fueled plants
has at least one CCR surface impoundment. At present, CCR is regulated by the states as solid waste.
Coal Combustion Residuals
The EPA's CCR rule, which took effect in October 2015, establishes 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 surface impoundments. The requirements include location restrictions, structural
integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping
and notification. The rule allows existing CCR surface impoundments to continue to operate for the remainder of their
operating life, but generally would require closure (i.e., cessation of placement of CCR material and corrective action necessary
to reach the standards provided in the CCR rule and applicable state rules) if groundwater monitoring demonstrates that the
CCR surface impoundment is responsible for exceedances of groundwater quality protection standards or the CCR surface
impoundment does not meet location restrictions or structural integrity criteria. The deadlines for beginning and completing
closure vary depending on several factors. Several petitions for judicial review of the CCR rule were filed. The Water
Infrastructure Improvements for the Nation Act (the WIIN Act), which was enacted in December 2016, provides for EPA
review and approval of state CCR permit programs.
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In July 2018, the EPA published a final rule, which became effective in August 2018, that amends certain provisions of
the CCR rule that the agency issued in 2015. Among other changes, the 2018 revisions extend closure deadlines to October 31,
2020, related to the aquifer location restriction and groundwater monitoring requirements. Also, in August 2018, the D.C.
Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability
exemption for legacy impoundments. The EPA is expected to undertake further revisions to its CCR regulations in response to
the D.C. Circuit Court's ruling. In October 2018, the rule that extends certain closure deadlines to 2020 was challenged in the
D.C. Circuit Court. In March 2019, the D.C. Circuit Court granted the EPA's request for remand without vacatur. In December
2019, the EPA issued a proposed rule that would revise the closure deadlines for unlined CCR impoundments from October 31,
2020 to August 31, 2020 and establish new procedures for seeking extensions of the August 31, 2020 closure deadline. One
method to receive an extension of the August 31, 2020 deadline would require notifying the EPA by May 2020 that the affected
power generation facility will retire by either 2023 or 2028 depending upon the size of the affected facility’s impoundments. If
the rule is finalized as proposed, we may decide to avail ourselves of this retirement extension mechanism for some of our
facilities. We filed comments on the proposal in January 2020. While we cannot predict the impacts of these rule revisions
(including whether and if so how the states in which we operate will utilize the authority delegated to the states through the
revisions), or estimate a range of reasonably possible costs related to these revisions, the changes that result from these
revisions could have a material impact on our results of operations, liquidity or financial condition.
MISO — 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 are working towards implementation of those closure plans.
At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the 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 for additional information regarding the closure of these Vermilion surface
impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options.
In May 2018, Prairie Rivers Network 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 judgment was
entered in our favor. Plaintiffs have appealed the judgment to the U.S. Court of Appeals for the Seventh Circuit. That appeal is
now stayed.
In April 2019, PRN also filed 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. This matter is in the early
stages. We dispute the allegations in both of these matters and will vigorously defend our position.
In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen
facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal
CCR rule. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface
impoundments at our retired Vermilion facility and that notice has since been referred to the Illinois Attorney General.
In December 2018, the Sierra Club filed a complaint with the IPCB alleging the disposal and storage of coal ash at the
Coffeen, Edwards, and Joppa generation facilities are causing exceedances of the applicable groundwater standards. We
dispute the allegations and will vigorously defend our position.
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. We anticipate IEPA's proposed rule will be issued
in March 2020 and expect the rulemaking process should be completed by early 2021. Under the new law, 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 law does not mandate closure by removal at any site. While we cannot predict
the outcome of this rulemaking process, the final rule could have a material impact on our ARO, results of operations, liquidity
or financial condition.
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For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are
necessary at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our
financial condition, results of operations, and cash flows. At this time, in part because of the revisions to the CCR rule that the
EPA published in July 2018, the D.C. Circuit Court's vacatur and remand of certain provisions of the EPA's 2015 CCR rule and
the Illinois coal ash rulemaking, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any,
that ultimately may be required. The currently anticipated CCR surface impoundment and landfill closure costs, as contained in
our AROs, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and
protective of the environment for each location.
Water
The EPA and the environmental regulatory bodies of states in which we operate have jurisdiction over the diversion,
impoundment and withdrawal of water for cooling and other purposes and the discharge of wastewater (including storm water)
from our facilities. We believe our facilities are presently in material compliance with applicable federal and state requirements
relating to these activities. We believe we hold all required permits relating to these activities for facilities in operation and
have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the
requirements necessary to obtain any required permits or renewals.
Cooling Water Intake Structures — Clean Water Act Section 316(b) regulations pertaining to existing water intake
structures at large generation facilities became effective in 2014. This provision generally requires that the location, design,
construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse
environmental impacts. Although the rule does not mandate a certain control technology, it does require site-specific
assessments of technology feasibility on a case-by-case basis at the state level.
At this time, we estimate the cost of our compliance with the cooling water intake structure rule to be approximately $16
million, depending on the final technology needed for compliance at our Illinois plants. Our estimate could change materially
depending upon a variety of factors, including site-specific determinations made by states in implementing the rule, the results
of impingement and entrainment studies required by the rule, the results of site-specific engineering studies and the outcome of
litigation concerning the rule and potential plant retirements.
Effluent Limitation Guidelines (ELGs) — In November 2015, the EPA revised the ELGs for steam electricity generation
facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue
gas desulfurization (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for
review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions
requesting reconsideration of the ELG final rule and administratively stayed the rule's compliance date deadlines.
In August
2017, the EPA announced that its reconsideration of the 2015 ELG final rule 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 2015 ELG Rule for the application of effluent limitations for FGD and bottom ash wastewaters from November 1, 2018
to November 1, 2020. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in
abeyance challenges to 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 rule pertaining to effluent limitations for legacy wastewater and leachate. In
November 2019, the EPA issued a proposal that would extend the compliance deadline for FGD wastewater to no later than
December 31, 2025 and maintains the December 31, 2023 compliance date for bottom ash transport water. The proposal also
creates new sub-categories of facilities with more flexible FGD compliance options, including a retirement exemption to 2028
and a low utilization boiler exemption. The proposed rule also modified some of the FGD final effluent limitations. We filed
comments on the proposal in January 2020.
Given the EPA's decision to reconsider the FGD and bottom ash wastewater provisions of the ELG rule, the rule
postponing the ELG rule's earliest compliance dates for those provisions, the uncertainty stemming from the vacatur of the
effluent limitations for legacy wastewater and leachate, and the intertwined relationship of the ELG rule with the CCR rule
discussed above, which is also being reconsidered by the EPA, as well as pending legal challenges concerning both rules,
substantial uncertainty exists regarding our projected capital expenditures for ELG compliance, including the timing of such
expenditures. While we cannot predict the outcome of this matter, or estimate a range of costs, it could have a material impact
on our results of operations, liquidity or financial condition.
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Radioactive Waste
The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily using
dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the U.S.
Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear
fuel storage capability is sufficient for the foreseeable future.
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Item 1A. RISK FACTORS
Please carefully consider the following discussion of significant factors, events, and uncertainties that make an
investment in our securities risky. These factors, in addition to others specifically addressed in Item 7. Management's
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.
factors, events and uncertainties were to materialize, it could cause results or outcomes to differ materially from those contained
in or implied by any forward-looking statement in this annual report on Form 10-K. There may be further risks and
uncertainties that are not currently known or that are not currently believed to be material that may adversely affect our
business, results of operations, liquidity, 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, results of operations and operating cash flows generally may be impacted by price fluctuations in the
wholesale power market and other market factors beyond our control.
We are not guaranteed any rate of return on capital investments in our businesses. We conduct integrated power
generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales
of electricity and natural gas to end users and commodity risk management. Our wholesale and retail businesses are to some
extent countercyclical in nature, particularly for the wholesale power and ancillary services supplied to the retail business.
However, we do have a wholesale power position that exceeds the overall load requirements of our retail business and is subject
to wholesale power price moves. As a result, our revenues, results of operations and operating cash flows depend in large part
upon wholesale market prices for electricity, natural gas, uranium, lignite, coal, fuel and transportation in our regional markets
and other competitive markets and upon prevailing retail electricity rates, which may be impacted by, among other things,
actions of regulatory authorities. Market prices for power, capacity, ancillary services, natural gas, coal and oil are
unpredictable and may fluctuate substantially over relatively short periods of time. Unlike most other commodities, electric
power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power
prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets.
Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. Over-supply can occur
as a result of the construction of new power plants, as we have observed in recent years. During periods of over-supply,
electricity prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities
with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules
and other mechanisms to address volatility and other issues in these markets.
The majority of our facilities operate as "merchant" facilities without long-term power sales agreements. As a result, we
largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and
retail power markets on a short-term basis and are not guaranteed any rate of return on our capital investments. Consequently,
there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those
facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon
prevailing market prices for power, capacity and fuel. Given the volatility of commodity power prices, to the extent we do not
secure long-term power sales agreements for the output of our power generation facilities, our revenues and profitability will be
subject to volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.
We purchase natural gas, coal, oil and nuclear fuel for our generation facilities, and higher than expected fuel costs or
volatility in these fuel markets may have an adverse impact on our costs, revenues, results of operations, financial condition
and cash flows.
We rely on natural gas, coal and oil to fuel the majority of our power generation facilities. Delivery of these fuels to the
facilities is dependent upon the continuing financial viability of contractual counterparties as well as upon the infrastructure
(including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve each generation
facility. As a result, we are subject to the risks of disruptions or curtailments in the production of power at our generation
facilities if no fuel is available at any price or if a counterparty fails to perform or if there is a disruption in the fuel delivery
infrastructure.
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We have sold forward a substantial portion of our expected power sales in the next one to two years in order to lock in
long-term prices. In order to hedge our obligations under these forward power sales contracts, we have entered into long-term
and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to
pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force
majeure events or the default of a fuel supplier or transporter. Fuel costs (including diesel, natural gas, lignite, coal and nuclear
fuel) may be volatile, and the wholesale price for electricity may not change at the same rate as changes in fuel costs, and
disruptions in our fuel supplies may therefore require us to find alternative fuel sources at higher costs, to find other sources of
power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as
contracted. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets
may affect costs incurred in meeting obligations. Further, any changes in the costs of coal, fuel oil, natural gas or transportation
rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we
are unable to procure fuel for physical delivery at prices we consider favorable, our financial condition, results of operations
and cash flows could be materially adversely affected.
We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate,
sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of energy
may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse
effect on our financial performance. Volatility in market prices for fuel and electricity may result from, among other factors:
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demand for energy commodities and general economic conditions;
volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;
volatility in market heat rates;
volatility in coal and rail transportation prices;
volatility in nuclear fuel and related enrichment and conversion services;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
severe or unexpected weather conditions, including drought and limitations on access to water;
seasonality;
changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;
illiquidity in the wholesale electricity or other commodity markets;
transmission or transportation disruptions, constraints, inoperability or inefficiencies, or other changes in power
transmission infrastructure;
development and availability of new fuels, new technologies and new forms of competition for the production and
storage of power, including competitively priced alternative energy sources or storage;
changes in market structure and liquidity;
changes in the way we operate our facilities, including curtailed operation due to market pricing, environmental
regulations and legislation, safety or other factors;
changes in generation capacity or efficiency;
outages or otherwise reduced output from our generation facilities or those of our competitors;
changes in electric capacity, including the addition of new supplies of power as a result of the development of new
plants, expansion of existing plants, the continued operation of uneconomic power plants due to federal, state or local
subsidies, or additional transmission capacity;
our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
changes in the credit risk or payment practices of market participants;
changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;
natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and
changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and
legislation.
We may be forced to retire or idle additional underperforming generation units, which could result in significant costs and
have an adverse effect on our operating results.
A sustained decrease in the financial results from, or the value of, our generation units ultimately could result in the
retirement or idling of additional generation units.
In recent years, we have operated certain of our lignite- and coal-fueled
generation assets only during parts of the year that have higher electricity demand and, therefore, higher related wholesale
electricity prices.
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Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging
transactions may not work as planned or hedge counterparties may default on their obligations.
Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notably
electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative
to the duration of available markets for various hedging activities. Generally, commodity markets that we participate in to
hedge our exposure to electricity prices and heat rates have limited liquidity after two to three years. Further, our ability to
hedge our revenues by utilizing cross-commodity hedging strategies with natural gas hedging instruments is generally limited to
a duration of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat
rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favorably or
unfavorably.
To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge
portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium
and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we
routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in
over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment
of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in
place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we
hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters,
consumer behavior, market constraints or other factors could cause us to purchase electricity to meet unexpected demand in
periods of high wholesale market prices or resell excess electricity into the wholesale market in periods of low prices. As a
result of these and other factors, risk management decisions may have a material adverse effect on us.
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.
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, participation by financial institutions and other intermediaries (including investment banks)
in such markets has declined. Extended declines in market liquidity could adversely affect our ability to hedge our financial
exposure to desired levels.
To the extent we engage in hedging and risk management activities, we are exposed to the credit risk that counterparties
that owe us money, energy or other commodities as a result of these activities will not perform their obligations to us. Should
the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or
honor the underlying commitment at then-current market prices. Additionally, our counterparties may seek bankruptcy
protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the
extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us. There
can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and
adversely affect our financial condition, results of operations and cash flows.
In such event, we could incur losses or forgo
expected gains in addition to amounts, if any, already paid to the counterparties. Market participants in the RTOs and ISOs in
which we operate are also exposed to risks that another market participant may default on its obligations to pay such RTO or
ISO for electricity or services taken, in which case such costs, to the extent not offset by posted security and other protections
available to such RTO or ISO, may be allocated to various non-defaulting RTO or ISO market participants, including us.
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We do not apply hedge accounting to our commodity derivative transactions, which may cause increased volatility in our
quarterly and annual financial results.
We engage in economic hedging activities to manage our exposure related to commodity price fluctuations through the
use of financial and physical derivative contracts for commodities. These derivatives are accounted for in accordance with
GAAP, which requires that we record all derivatives on the balance sheet at fair value with changes in fair value immediately
recognized in earnings as unrealized gains or losses. GAAP permits an entity to designate qualifying derivative contracts as
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 financial results in accordance with GAAP are subject to
significant fluctuations caused by changes in forward commodity prices.
Competition, change in market structure, and/or state or federal interference in the wholesale and retail power markets,
together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and
cash flows.
Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale
marketplace may be undermined by changes in market structure and out-of-market subsidies provided by federal or state
entities, including bailouts of uneconomic plants, imports of power from Canada, renewable mandates or subsidies, as well as
out-of-market payments to new generators.
Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of
regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary
services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for
power may be met by generation capacity based on several competing technologies, as well as power generating facilities
fueled by alternative or renewable energy sources,
including hydroelectric power, synthetic fuels, solar, wind, wood,
geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable
generation increases competition from these types of facilities and out-of-market subsidies to existing or new generation can
undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those
owned by us.
We also compete against other energy merchants on the basis of our relative operating skills, financial position and access
to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit
support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we
compete may have greater resources or experience in these areas. Over time, some of our plants may become unable to
compete because of subsidized generation, including public utility commission supported power purchase agreements, and the
construction of new plants. Such new plants could have a number of advantages including: more efficient equipment, newer
technology that could result
in fewer emissions or more advantageous locations on the electric transmission system.
Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer
technology utilized in their facilities or the additional resources derived from owning more efficient facilities.
Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors
have entered the industry, including financial investors who perceive that asset values are at levels below their true replacement
value. As a result, a number of generation facilities in the U.S. are now owned by lenders and investment companies.
Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we
anticipate that we will face competition from numerous companies in the industry. Certain federal and state entities in
jurisdictions in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise
uneconomic plants and attempt to incent the development of new renewable resources as well as increase energy efficiency
investments. Continued subsidies (or increases thereto) to our competitors could have a material adverse effect on our financial
condition, results of operations and cash flows.
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In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins
that we can earn on the volumes we are able to serve. Further, with retail competition, it is easier for residential customers
where we serve load to switch to and from competitive electricity generation suppliers for their energy needs. The volatility
and uncertainty that results from such mobility may have material adverse effects on our financial condition, results of
operations and cash flows. For example, if fewer customers switch to another supplier than anticipated, the load we must serve
will be greater than anticipated and, if market prices of fuel have increased, our costs will increase more than expected due to
the need to go to the market to cover the incremental supply obligation.
If more customers switch to another supplier than
anticipated, the load we must serve will be lower than anticipated and, if market prices of electricity have decreased, our
operating results could suffer.
Our results of operations and financial condition could be materially and adversely affected if energy market participants
continue to construct additional generation facilities (i.e., new-build) or expand or enhance existing generation facilities
despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices.
Given the overall attractiveness of certain of the markets in which we operate and certain tax benefits associated with
renewable energy, among other matters, energy market participants have continued to construct new generation facilities (i.e.,
new-build) or invest in enhancements or expansions of existing generation facilities despite relatively low wholesale power
prices.
If this market dynamic continues, our results of operations and financial condition could be materially and adversely
affected if such additional generation capacity results in an over-supply of electricity that causes a reduction in wholesale power
prices.
Unauthorized hedging and related activities by our employees could result in significant losses.
We have various internal policies, processes, and controls designed to monitor hedging activities and positions. These
policies, processes, and controls are designed, in part, to prevent unauthorized purchases or sales of products by our employees
or alert our risk management teams of any trades that have not been entered into our risk management systems. We cannot
assure, however, that these steps will detect and prevent inaccurate reporting and all potential violations of our risk management
policies, processes, and controls, particularly if deception or other intentional misconduct is involved. A significant policy
violation that is not detected could result in a substantial financial loss.
Our risk management policies cannot fully eliminate the risk associated with our commodity hedging activities.
Our operations and other commodity hedging activities expose us to risks of commodity price movements. We attempt to
manage this exposure by entering into commodity hedging transactions and establishing risk management policies and
procedures. These risk management procedures may not work as planned and cannot eliminate all risks associated with these
activities. As a result, we cannot fully predict the impact that our commodity hedging activities and risk management decisions
may have on our business and/or financial condition, results of operations and cash flows.
Economic downturns would likely have a material adverse effect on our businesses.
Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including
low levels in the market prices for power, generation capacity and natural gas, which can fluctuate substantially.
Increased
unemployment of residential customers and decreased demand for products and services by commercial and industrial
customers resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number
of uncollectible customer balances, which would negatively impact our overall sales and cash flows. Additionally, prolonged
economic downturns that negatively impact our financial condition, results of operations and cash flows could result in future
material impairment charges to write down the carrying value of certain assets to their respective fair values.
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Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during
times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in
the future, which could have a material adverse effect on us. We currently maintain non-investment grade credit ratings
that could negatively affect our ability to access capital on favorable terms or result in higher collateral requirements,
particularly if our credit ratings were to be downgraded in the future.
Our businesses are capital intensive. In general, we rely on access to financial markets and credit facilities as a significant
source of liquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The
inability to raise capital or to access credit facilities, particularly on favorable terms, could adversely impact our liquidity and
our ability to meet our obligations or sustain and grow our businesses and could increase capital costs and collateral
requirements, any of which could have a material adverse effect on us.
Our access to capital and the cost and other terms of acquiring capital are dependent upon, and could be adversely
impacted by, various factors, including:
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general economic and capital markets conditions, including changes in financial markets that reduce available
liquidity or the ability to obtain or renew credit facilities on favorable terms or at all;
conditions and economic weakness in the U.S. power markets;
regulatory developments;
changes in interest rates;
a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;
a downgrade of Vistra Energy's or its applicable subsidiaries' credit ratings, or credit ratings of its issuances;
our level of indebtedness and compliance with covenants in our debt agreements;
a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit
facilities that affects the ability of such lender(s) to make loans to us;
security or collateral requirements;
general credit availability from banks or other lenders for us and our industry peers;
investor confidence in the industry and in us and the wholesale electricity markets in which we operate;
volatility in commodity prices that increases credit requirements;
a material breakdown in our risk management procedures;
the occurrence of changes in our businesses;
disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities, and
changes in or the operation of provisions of tax and regulatory laws.
In addition, we currently maintain non-investment grade credit ratings. As a result, we may not be able to access capital
on terms (financial or otherwise) as favorable as companies that maintain investment-grade credit ratings or we may be unable
to access capital at all at times when the credit markets tighten. In addition, our non-investment grade credit ratings may result
in counterparties requesting collateral support (including cash or letters of credit) in order to enter into transactions with us.
A downgrade in long-term debt ratings generally causes borrowing costs to increase and the potential pool of investors to
shrink and could trigger liquidity demands pursuant to contractual arrangements. Future transactions by Vistra Energy or any
of its subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit
ratings.
Our indebtedness and the proposed phase out of LIBOR could adversely affect our ability in the future to raise additional
capital to fund our operations. It could also expose us to the risk of increased interest rates and limit our ability to react to
changes in the economy, or our industry, as well as impact our cash available for distribution.
As of December 31, 2019, we had approximately $11.2 billion of total indebtedness and approximately $10.9 billion of
indebtedness net of cash. Our debt could have negative consequences for our financial condition including:
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requiring a significant portion of our cash flow from operations to be dedicated to the payment of principal and
interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our common stock or to
fund our operations, capital expenditures and future business opportunities;
limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
limiting our ability to fund operations or future acquisitions;
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restricting our ability to make distributions or pay dividends with respect to our capital stock and the ability of our
subsidiaries to make distributions to us, in light of restricted payment and other financial covenants in our credit
facilities and other financing agreements;
inhibiting the growth of our stock price;
exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under the
Vistra Operations Credit Facilities, are at variable rates of interest;
limiting our ability to obtain additional financing for working capital
expenditures, debt service requirements, acquisitions and general corporate or other purposes, and
limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to
our competitors who may have less debt.
including collateral postings, capital
We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to
refinance or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof. Our
failure to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default
under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of
operations and cash flows.
In addition, a portion of our indebtedness bears interest at variable interest rates, primarily based on LIBOR. Vistra Energy
employs interest rate swaps to hedge our exposure to changes in LIBOR for a significant portion of this variable rate
indebtedness. In 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop
compelling banks to submit rates for the calculation of LIBOR after 2021.
It is unclear whether new methods of calculating
LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the
Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated
based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these proposed changes,
other potential reforms or the establishment of any other alternative reference rates in the United Kingdom, the U.S. or
elsewhere, including whether we will be able to amend the Vistra Operations Credit Facilities and/or our interest rate swaps to
adequately reflect such changes, reforms or alternative reference rates. Accordingly, we could be exposed to increased costs
with respect to our variable rate debt, which could have an adverse impact on extensions of our credit and/or we might not be
fully hedged on the variable rate exposure on our swapped indebtedness. Any such increased costs or exposure could increase
our cost of capital and have a material adverse effect on us.
The Vistra Operations Credit Facilities impose restrictions on us and any failure to comply with these restrictions could have
a material adverse effect on us.
The Vistra Operations Credit Facilities contain restrictions that could adversely affect us by limiting our ability to plan
for, or react to, market conditions or to meet our capital needs and could result in an event of default under the Vistra
Operations Credit Facilities. The Vistra Operations Credit Facilities contain events of default customary for financings of this
type.
If we fail to comply with the covenants in the Vistra Operations Credit Facilities and are unable to obtain a waiver or
amendment, or a default exists and is continuing, the lenders under such agreements could give notice and declare outstanding
borrowings thereunder immediately due and payable. Any such acceleration of outstanding borrowings could have a material
adverse effect on us.
Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs. If we are unable
to provide such security, it may restrict our ability to conduct our business, which could have a material adverse effect on us.
We undertake certain hedging and commodity activities and enter into certain financing arrangements with various
counterparties that require cash collateral or the posting of letters of credit which are at risk of being drawn down in the event
we default on our obligations. We currently use margin deposits, prepayments and letters of credit as credit support for
commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent
of our involvement in standard contracts and movements in commodity prices, and also based on our credit ratings and the
general perception of creditworthiness in the markets in which we operate. In the case of commodity arrangements, the amount
of such credit support that must be provided typically is based on the difference between the price of the commodity in a given
contract and the market price of the commodity. Significant movements in market prices can result in our being required to
provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the
amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we
anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral, we may not be able to
manage price volatility effectively or to implement our strategy. An increase in the amount of letters of credit or cash collateral
required to be provided to our counterparties may have a material adverse effect on us.
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We may not be able to complete future acquisitions or successfully integrate future acquisitions into our business, which
could result in unanticipated expenses and losses.
As part of our growth strategy, including our desire to grow our retail platform, we may pursue acquisitions of assets or
operating entities. Our ability to continue to implement this component of our growth strategy will be limited by our ability to
identify appropriate acquisition or joint venture candidates and our financial resources, including available cash and access to
capital. Any expense incurred in completing acquisitions or entering into joint ventures, the time it takes to integrate an
acquisition or our failure to integrate acquired businesses successfully could result in unanticipated expenses and losses.
Furthermore, we may not be able to fully realize the anticipated benefits from any future acquisitions or joint ventures we may
pursue.
In addition, the process of integrating acquired operations into our existing operations may result in unforeseen
operating difficulties and expenses and may require significant financial resources that would otherwise be available for the
execution of our business strategy.
Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition.
In evaluating our business and the strategic fit of our various assets, we may determine to sell one or more of such assets.
Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an
acceptable price and on acceptable terms and in a timely manner.
In addition, a prospective buyer may have difficulty
obtaining financing. Divestitures could involve additional risks, including:
difficulties in the separation of operations and personnel;
the need to provide significant ongoing post-closing transition support to a buyer;
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the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;
the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;
the disruption of our business, and
potential loss of key employees.
We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset,
which could adversely affect our results of operations and financial condition.
If our goodwill, intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to
earnings.
We have significant goodwill, intangible assets and long-lived assets recorded on our balance sheet. In accordance with
U.S. GAAP, goodwill and non-amortizing intangible assets are required to be tested for impairment at least annually.
Additionally, we review goodwill, our intangible assets and long-lived assets for impairment when events or changes in
circumstances indicate the carrying value of the asset may not be recoverable. Factors that may be considered include a decline
in future cash flows, slower growth rates in the energy industry, and a sustained decrease in the price of our common stock.
We performed our annual assessment of goodwill and non-amortizing intangibles in the fourth quarter of 2019 and
determined that no impairment was required. However, impairment assessments will be performed in future periods and may
result in an impairment loss, which could be material.
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Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in
an ownership change as defined in Internal Revenue Code (IRC) §382 could further limit our ability to use our federal net
operating losses to offset our future taxable income.
If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs that could be
used in any one year following such ownership change could be substantially limited. In general, an "ownership change" would
occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of
which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock. Given IRC §382's broad
definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is
outside our control. Vistra Energy acquired NOLs from its merger with Dynegy, however, Vistra Energy's use of such
attributes is limited under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy. If there is
an "ownership change" with respect to Vistra Energy (including by the normal trading activity of greater than 5% stockholders),
the utilization of all NOLs existing at that time would be subject to additional annual limitations based upon a formula provided
under IRC §382 that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership
change.
Recent U.S. tax legislation may materially adversely affect Vistra Energy's financial condition, results of operations and
cash flows.
On December 22, 2017, President Trump signed into law a comprehensive tax reform bill (the TCJA), that significantly
reforms the Internal Revenue Code. The TCJA, among other things, contains significant changes to corporate taxation,
including a reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense,
limitation of the deduction for certain net operating losses to 80% of current year taxable income, an indefinite net operating
loss carryforward, immediate deductions for certain new investments instead of deductions for depreciation expense over time
and the modification or repeal of many business deductions and credits. While we expect a beneficial impact from the TCJA
from the reduction in corporate tax rates and immediate deductions for certain new investments, we continue to examine the tax
reform legislation, as its overall impact is uncertain, and note that certain provisions of the TCJA or its interaction with existing
law could adversely affect the Company's business and financial condition. The impact of this tax reform legislation on our
stockholders is also uncertain and could be adverse.
We may be responsible for U.S. federal and state income tax liabilities that relate to the PrefCo Preferred Stock Sale and
Spin-Off.
Pursuant to the Tax Matters Agreement, the parties thereto have agreed to take certain actions and refrain from taking
certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a
breach of such covenant results in additional taxes to the other parties.
If we breach such a covenant (or, in certain
circumstances, if our stockholders or creditors of our Predecessor take or took certain actions that result in the intended tax
treatment of the Spin-Off not to be preserved), we may be required to make substantial indemnification payments to the other
parties to the Tax Matters Agreement.
The Tax Matters Agreement also allocates the responsibility for taxes for periods prior to the Spin-Off between EFH
Corp. and us. For periods prior to the Spin-Off, (i) Vistra Energy is generally required to reimburse EFH Corp. with respect to
any taxes paid by EFH Corp. that are attributable to us and (ii) EFH Corp. is generally required to reimburse us with respect to
any taxes paid by us that are attributable to EFH Corp.
We are also required to indemnify EFH Corp. against certain taxes in the event the IRS or another taxing authority
successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH
Corp.'s net operating loss deductions.
Our indemnification obligations to EFH Corp. are not limited by any maximum amount. If we are required to indemnify
EFH Corp. or such other persons under the circumstances set forth in the Tax Matters Agreement, we may be subject to
substantial liabilities.
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We are required to pay the holders of TRA Rights for certain tax benefits, which amounts are expected to be substantial.
On the Effective Date, we entered into the TRA with American Stock Transfer & Trust Company, LLC, as the transfer
agent. Pursuant to the TRA, we issued beneficial interests in the rights to receive payments under the TRA (TRA Rights) to the
first lien creditors of our Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to
receive such TRA Rights under the Plan of Reorganization. Our financial statements reflect a liability of $455 million as of
December 31, 2019 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 could be materially different than this estimate.
The TRA provides for the payment by us to the holders of TRA Rights of 85% of the amount of cash savings, if any, in
U.S. federal, state and local income tax that we and our subsidiaries actually realize as a result of our use of (a) the tax basis
step up attributable to the PrefCo Preferred Stock Sale, (b) the entire tax basis of the assets acquired as a result of the purchase
and sale agreement, dated as of November 25, 2015 by and between La Frontera Ventures, LLC and Luminant, and (c) tax
benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA. The amount and timing of
any payments under the TRA will vary depending upon a number of factors, including the amount and timing of the taxable
income we generate in the future and the tax rate then applicable, our use of loss carryovers and the portion of our payments
under the TRA constituting imputed interest.
Although we are not aware of any issue that would cause the IRS to challenge the tax benefits that are the subject of the
TRA, recipients of the payments under the TRA will not be required to reimburse us for any payments previously made if such
tax benefits are subsequently disallowed. As a result, in such circumstances, Vistra Energy could make payments under the
TRA that are greater than its actual cash tax savings. Any amount of excess payment can be used to reduce future TRA
payments, but cannot be immediately recouped, which could adversely affect our liquidity.
Because Vistra Energy is a holding company with no operations of its own, its ability to make payments under the TRA is
dependent on the ability of its subsidiaries to make distributions to it. To the extent that Vistra Energy is unable to make
payments under the TRA because of the inability of its subsidiaries to make distributions to us for any reason, such payments
will be deferred and will accrue interest until paid, which could adversely affect our results of operations and could also affect
our liquidity in periods in which such payments are made.
The payments we will be required to make under the TRA could be substantial.
We may be required to make an early termination payment to the holders of TRA Rights under the TRA.
The TRA provides that, in the event that Vistra Energy breaches any of its material obligations under the TRA, or upon
certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under
the TRA may treat such event as an early termination of the TRA, in which case Vistra Energy would be required to make an
immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100
basis points) of the anticipated future tax benefits based on certain valuation assumptions.
As a result, upon any such breach or change of control, we could be required to make a lump sum payment under the TRA
before we realize any actual cash tax savings and such lump sum payment could be greater than our future actual cash tax
savings.
The aggregate amount of these accelerated payments could be materially more than our estimated liability for payments
made under the TRA set forth in our financial statements. Based on this estimation, our obligations under the TRA could have
a substantial negative impact on our liquidity.
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We are potentially liable for U.S. income taxes of the entire EFH Corp. consolidated group for all taxable years in which we
were a member of such group.
Prior to the Spin-Off, EFH Corporate Services Company, EFH Properties Company and certain other subsidiary
corporations were included in the consolidated U.S. federal income tax group of which EFH Corp. was the common parent
(EFH Corp. Consolidated Group). In addition, pursuant to the private letter ruling from the IRS that we received in connection
with the Spin-Off, Vistra Energy will be considered a member of the EFH Corp. Consolidated Group immediately prior to the
Spin-Off. Under U.S. federal income tax laws, any corporation that is a member of a consolidated group at any time during a
taxable year is severally liable for the group's entire federal income tax liability for the entire taxable year. In addition, entities
that are disregarded for U.S. federal income tax purposes may be liable as successors under common law theories or under
certain regulations to the extent corporations transferred assets to such entities or merged or otherwise consolidated into such
entities, whether under state law or purely as a matter of federal income tax law. Thus, notwithstanding any contractual rights
to be reimbursed or indemnified by EFH Corp. pursuant to the Tax Matters Agreement, to the extent EFH Corp. or other
members of the EFH Corp. Consolidated Group fail to make any U.S. federal income tax payments required of them by law in
respect of taxable years for which the Company or any subsidiary noted above was a member of the EFH Corp. Consolidated
Group, the Company or such subsidiary may be liable for the shortfall. At such time, we may not have sufficient cash on hand
to satisfy such payment obligation.
Our ability to claim a portion of depreciation deductions may be limited for a period of time.
Under the Internal Revenue Code of 1986, as amended, a corporation's ability to utilize certain tax attributes, including
depreciation, may be limited following an ownership change if the corporation's overall asset tax basis exceeds the overall fair
market value of its assets (after making certain adjustments). The Spin-Off resulted in an ownership change for the Company
and it is expected that the overall tax basis of our assets may have exceeded the overall fair market value of our assets at such
time. As a result, there may be a limitation on our ability to claim a portion of our depreciation deductions for a five-year
period. This limitation could have a material impact on our tax liabilities and on our obligations under the TRA Rights.
In
addition, any future ownership change of Vistra Energy following Emergence could likewise result in additional limitations on
our ability to use certain tax attributes existing at the time of any such ownership change and have an impact on our tax
liabilities and on our obligations under the TRA.
Regulatory and Legislative Risks
Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the
future impact, our businesses, results of operations, liquidity and financial condition.
Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory
initiatives regarding the restructuring of the energy industry, including competition in power generation and sale of electricity.
Although we attempt to comply with changing legislative and regulatory requirements, there is a risk that we will fail to adapt
to any such changes successfully or on a timely basis.
Our businesses are subject to numerous state and federal laws (including, but not limited to, PURA, the Federal Power
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
Reform 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 FTC, CFTC, state
public utility commissions and state environmental regulatory agencies), and the rules, guidelines and protocols of ERCOT,
CAISO, ISO-NE, MISO, NYISO and PJM with respect to various matters, including, but not limited to, market structure and
design, operation of nuclear generation facilities, construction and operation of other generation facilities, development,
operation and reclamation of lignite mines, recovery of costs and investments, decommissioning costs, market behavior rules,
present or prospective wholesale and retail competition, rates for wholesale sales of electricity, mandatory reliability standards
and environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market
behavior and other competition-related rules and regulations under PURA. Changes in, revisions to, or reinterpretations of,
existing laws and regulations may have a material adverse effect on us.
27
Dynegy's legacy business operates in a number of states and markets outside of our historical operations. As a result of
the Merger, we became subject to the regulatory requirements of such markets, including CAISO, ISO-NE, MISO, NYISO and
PJM. As a result of the Crius Acquisition and the Ambit Acquisition, we became subject to the regulatory requirements of such
markets, including regulations of the sale of natural gas in the California, District of Columbia, Illinois, Indiana, Kentucky,
Maryland, New Jersey, New York, Michigan, Montana, Ohio, Pennsylvania and Virginia markets. Additionally, as further
described below, Ambit operates a direct selling business model for the sale of electricity which subjects us to additional
regulatory requirements in the states in which Ambit has retail electric customers and independent consultants. Ambit's direct
selling business is subject to a number of federal and state regulations administered by the FTC and various state agencies as
well as regulations in foreign markets administered by foreign agencies. Regulations applicable to network marketing
organizations generally are directed at ensuring that product sales ultimately are made to consumers and that advancement
within the organization is based on sales of the organization’s products rather than investments in the organization or other non-
retail sales related criteria. Because we have historically not been subject to the regulations of such markets and because we
have not historically operated a direct selling business model, we may incur additional expenses, which may be material, to
understand the relevant regulations and ensure that we are operating in compliance with such regulations.
Finally, the regulatory environment has undergone significant changes in the last several years due to state and federal
policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new
renewable generation. For example, changes to, or development of, legislation that requires the use of clean renewable and
alternate fuel sources or mandate the implementation of energy conservation programs that require the implementation of new
technologies, could increase our capital 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 companies
to construct or acquire generating facilities. Other proposals to re-regulate the retail energy industry may be made, and
legislative or other actions affecting electricity and natural gas deregulation or restructuring process may be delayed,
If such changes were to be
discontinued or reversed in states in which we currently operate or may in the future operate.
enacted by a regulatory body, we may lose customers, incur higher costs and/or find it more difficult to acquire new customers.
These changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effect that
the changing regulatory environment will have on our business.
We are required to obtain, and to comply with, government permits and approvals.
We are required to obtain, and to comply with, numerous permits and licenses from federal, state and local governmental
agencies. The process of obtaining and renewing necessary permits and licenses can be lengthy and complex and can
sometimes result in the establishment of conditions that make the project or activity for which the permit or license was sought
unprofitable or otherwise unattractive.
to denial, revocation or
modification under various circumstances. Failure to obtain or comply with the conditions of permits or licenses, or failure to
comply with applicable 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 laws 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
Our inability to procure and comply with the permits and licenses required for our operations, or the cost to us of such
In addition, new environmental legislation or
procurement or compliance, could have a material adverse effect on us.
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 applicable laws
and regulations.
In addition to the possible imposition of fines in the case of any such violations, we may be required to
undertake significant capital investments and obtain additional operating permits or licenses, which could have a material
adverse effect on us.
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Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.
We are subject
to extensive environmental regulation by governmental authorities,
including the EPA and state
environmental agencies and/or attorneys general. We may incur significant additional costs beyond those currently
contemplated to comply with these regulatory requirements. If we fail to comply with these regulatory requirements, we could
be subject to administrative, civil or criminal liabilities and fines. Existing environmental regulations could be revised or
reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in
environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air
emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing
requirements. Any of the foregoing could have a material adverse effect on us.
The EPA has recently finalized or proposed several regulatory actions establishing new requirements for control of certain
emissions from sources, including electricity generation facilities.
In the future, the EPA may also propose and finalize
additional regulatory actions that may adversely affect our existing generation facilities or our ability to cost-effectively develop
new generation facilities. There is no assurance that the currently installed emissions control equipment at our lignite, coal and/
or natural gas-fueled generation facilities will satisfy the requirements under any future EPA or state environmental regulations.
Some of the recent regulatory actions, such as the EPA's ACE rule and proposed or future actions, including the Regional Haze
program, could require us to install significant additional control equipment, resulting in potentially material costs of
compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production
curtailments. These costs could have a material adverse effect on us.
We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining
any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an
approval is retroactively disallowed or adversely modified, the operation of our generation facilities could be stopped,
disrupted, curtailed or modified or become subject to additional costs. Any such stoppage, disruption, curtailment, modification
or additional costs could have a material adverse effect on us.
In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that
we have acquired, leased, 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 liabilities. Another party could, depending on the circumstances, assert an environmental claim
against us or fail to meet its indemnification obligations to us.
We could be materially and adversely affected if current regulations are implemented or if new federal or state legislation or
regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or
property resulting from greenhouse gas emissions.
There is 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
incentives for the
allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions,
development of low-carbon technology and federal renewable portfolio standards.
In July 2019, the EPA finalized the ACE
rule that develops emissions guidelines that states must use when developing plans to regulate GHG emissions from existing
coal-fueled electric generating units. States where we operate coal plants (Texas, Illinois and Ohio) have begun the
development of their state plans to comply with the ACE rule. In addition, a number of federal court cases have been filed in
recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse
precedent that might apply to companies (including us) that produce GHG emissions. We could be materially and adversely
affected if new federal and/or state legislation or regulations are adopted to address global climate change or if we are subject to
lawsuits for alleged damage to persons or property resulting from GHG emissions.
The integration of the Capacity Performance product into the PJM market and the Pay-for-Performance mechanism in
ISO-NE could lead to substantial changes in capacity income and non-performance penalties, which could have a material
adverse effect on our results of operations, financial condition and cash flows.
Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time
generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. We
may experience substantial changes in capacity income and non-performance penalties, which could have a material adverse
effect on our results of operations, financial condition and cash flows.
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The availability and cost of emission allowances could adversely impact our costs of operations.
We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2, CO2 and
NOX to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to
meet the obligations imposed on us by various applicable environmental laws. If our operational needs require more than our
allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly.
If we are
unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as
not to exceed our available emission allowances or install costly new emission controls. As we use the emission allowances
that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If
such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could
materially increase our costs of operations in the affected markets.
Luminant's mining operations are subject to RCT oversight.
We currently own and operate, or are in the process of reclaiming, 12 surface lignite coal mines in Texas to provide fuel
for our electricity generation facilities. We also own or lease, and are in the process of reclaiming, two waste-to-energy surface
facilities in Pennsylvania. The RCT, which exercises broad authority to regulate reclamation activity, reviews on an ongoing
basis whether Luminant is compliant with RCT rules and regulations and whether it has met all the requirements of its mining
permits. Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface Mining, which
also regulates mining activity nationwide, or any changes in the interpretation of existing rules and regulations, could result in
higher compliance costs or otherwise adversely affect our financial condition or cause a revocation of a mining permit. Any
revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to
serve its generation facilities.
Luminant's lignite mining reclamation activity will require significant resources as existing and retired mining operations
are reclaimed over the next several years.
In conjunction with Luminant's announcements in 2017 to retire several power generation assets and related mining
operations, along with the continuous reclamation activity at its continuing mining operations for its mines related to the Oak
Grove and Martin Lake generation assets, Luminant is expected to spend a significant amount of money, internal resources and
time to complete the required reclamation activities. For the next five years, Vistra Energy is projected to spend approximately
$340 million (on a nominal basis) to achieve its reclamation objectives.
Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant
liabilities and reputation damage that could have a material adverse effect on us.
We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment,
commercial, and environmental issues, and other claims for injuries and damages. We evaluate litigation claims and legal
proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based
on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the
relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information
available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ
materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a
material adverse effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation
environment poses a significant business risk.
We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings,
and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative
proceedings. While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such
regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have
a materially adverse effect on us.
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Our retail businesses, which each have REP certifications that are subject to review of the public utility commissions in the
states in which we operate, are subject to changing state rules and regulations that could have a material impact on the
profitability of our business.
The competitiveness of our retail businesses partially depends on state regulatory policies that establish the structure,
rules, terms and conditions on which services are offered to retail customers. Specifically, the public utility commissions and/
or the attorney generals of the various jurisdictions in which the Retail segment operates may at any time initiate an
investigation into whether our retail operations comply with certain commission rules or state laws and whether we have met
the requirements for REP certification, including financial requirements. These state policies and investigations, which can
include controls on the retail rates our retail businesses can charge, the imposition of additional costs on sales, restrictions on
our ability to obtain new customers through various marketing channels and disclosure requirements, investigations into
whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for
REP certification, including financial requirements, can affect the competitiveness of our retail businesses. Any removal or
revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail
customers in the applicable jurisdiction, and such decertification could have a material adverse effect on us. Additionally, state
or federal imposition of net metering or renewable portfolio standard programs can make it more or less expensive for retail
customers to supplement or replace their reliance on grid power. Our retail businesses have limited ability to influence
development of these state rules, regulations and policies, and our business model may be more or less effective, depending on
changes to the regulatory environment.
Ambit's direct selling business model could be found to be not in compliance with current or newly adopted laws or
regulations in one or more markets, which could prevent us from conducting our business in these markets or require us to
alter compensation practices under our direct selling business model, and harm our results of operations and financial
condition.
Ambit's direct selling business model is subject to a number of federal and state regulations administered by the FTC and
various federal and state agencies in the U.S. as well as regulations on direct selling in foreign markets administered by foreign
agencies. We are subject to the risk that, in one or more markets, our direct selling business could be found by federal, state or
foreign regulators not to be in compliance with applicable law or regulations, which may lead to our inability to obtain or
maintain a license, permit, or similar certification. We may also be required to alter compensation practices under our direct
selling business in order to comply with applicable federal, state, or foreign law or regulations. Regulations applicable to direct
selling businesses generally are directed at preventing fraudulent or deceptive schemes, sometimes referred to as "pyramid" or
"chain sales" schemes, by ensuring that product sales ultimately are made to consumers and that advancement within an
organization is based on sales of the organization’s products rather than investments in the organization or other non-retail
sales-related criteria. The regulatory requirements concerning direct selling businesses do not include "bright line" rules and
are inherently fact-based and, thus, we are subject to the risk that these laws or regulations or the enforcement or interpretation
of these laws and regulations by governmental agencies or courts can change. The ambiguity surrounding these laws can also
affect the public perception of the Company.
In the U.S., the FTC has entered into several highly publicized settlements pursuant to consent orders with direct selling
companies that required those companies to modify their compensation plans and business models. Those settlements resulted
from actions brought by the FTC involving a variety of alleged violations of consumer protection laws, including misleading
earnings representations by the companies' independent distributors, as well as the legal validity of the companies' business
model and distributor compensation plans. The consent order in each of these cases required the respective direct selling
company to, among other things, pay a significant fine, revise its U.S. business model and compensation plan to comply with
various restrictions on how it can compensate independent distributors and change its marketing practices to avoid misleading
income representations. Although we strive to ensure that Ambit's overall business model and compensation plans are
regulatory compliant in each of our markets, we cannot provide assurance that a regulator, if it were to review our business,
would agree with our assessment and would not require us to change one or more aspects of our operations. Being the target of
an investigation or enforcement action by the FTC could have a material adverse effect on our results of operations and
financial condition.
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We are also subject to the risk of private party challenges to the legality of our direct selling business. Some direct selling
channels of other companies have been successfully challenged in the past, while other challenges to direct selling channels of
other companies have been defeated. Adverse judicial determinations with respect to our direct selling channel, or in
proceedings not involving us directly but which challenge the legality of direct selling channels, in any market in which we
operate, could negatively impact our business. Violations of applicable law or of our policies and procedures by independent
contractors participating in Ambit's direct selling channel could also reflect negatively on us or harm our business reputation.
While we have implemented policies and procedures designed to govern independent contractor conduct and to protect the
goodwill associated with Ambit's trademarks and tradenames, it can be difficult to enforce these policies and procedures
because of the large number of independent contracts and their independent status. In addition, it is possible that a court could
hold us civilly or criminally accountable based on vicarious liability because of the actions of those independent contractors or
challenge the independent contractor status of those individuals.
Operational Risks
Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance
of our retail businesses.
Although we are the primary provider of our retail businesses' wholesale electricity supply requirements, our retail
businesses purchase a portion of their supply requirements from third parties. As a result, the financial performance of our
retail business depends on their ability to obtain adequate supplies of electric generation from third parties at prices below the
prices they charge their customers. Consequently, our earnings and cash flows could be adversely affected in any period in
which the retail businesses' wholesale electricity supply costs rise at a greater rate than the rates they charge to customers. The
price of wholesale electricity supply purchases associated with the retail businesses' energy commitments can be different than
that reflected in the rates charged to customers due to, among other factors:
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varying supply procurement contracts used and the timing of entering into related contracts;
subsequent changes in the overall price of natural gas;
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
transmission constraints and the Company's ability to move power to our customers, and
changes in market heat rate.
The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers'
actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors,
weather events, competition and economic conditions.
Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing
customers and the inability to attract new customers.
We operate in a very competitive retail market and, as a result, our retail operation faces significant competition for
customers. We believe our brands are viewed favorably in the retail electricity markets in which we operate, but despite our
commitment to providing superior customer service and innovative products, customer sentiment toward our brands, including
by comparison to our competitors' brands, depends on certain factors beyond our control. For example, competitor REPs may
offer different products, lower electricity prices and other incentives, which, despite our long-standing relationship with many
customers, may attract customers away from us. If we are unable to successfully compete with competitors in the retail market
it is possible our retail customer counts could decline, which could have a material adverse effect on us.
As we try to grow our retail business and operate our business strategy, we compete with various other REPs that may
have certain advantages over us. For example, in new markets, our principal competitor for new customers may be the
incumbent REP, which has the advantage of long-standing relationships with its customers, including well-known brand
In addition to competition from the incumbent REP, we may face competition from a number of other energy
recognition.
service providers, other energy industry participants, or nationally branded providers of consumer products and services who
may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger than we
are or have greater resources or access to capital than we have.
If there is inadequate potential margin in retail electricity
markets with substantial competition to overcome the adverse effect of relatively high customer acquisition costs in such
markets, it may not be profitable for us to compete in these markets.
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Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide
electricity to, and to obtain information about, our customers. Any infrastructure failure could negatively impact customer
satisfaction and could have a material adverse effect on us.
The substantial majority of our retail operations depend on transmission and distribution facilities owned and operated by
unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capacity is inadequate, our ability to
sell and deliver electricity may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is
available in the capacity-constrained area, or, with respect to capacity performance in PJM and performance incentives in ISO-
NE, we may be subject to significant penalties. For example, during some periods, transmission access is constrained in some
areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to
these customers may exceed the cost to provide service to other customers, resulting in lower operating margins. In addition,
any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer
satisfaction with our service. Any of the foregoing could have a material adverse effect on us.
The operation of our businesses is subject to cyber-based security and integrity risk. Attacks on our infrastructure that
breach cyber/data security measures could expose us to significant liabilities and reputation damage and disrupt business
operations, which could have a material adverse effect on us.
Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage,
processing and communication of electronic data and the use of sophisticated computer hardware and software systems and
much of our information technology infrastructure is connected (directly or indirectly) to the internet. Our information
technology systems and infrastructure are susceptible to damage, disruptions, or shutdowns due to power outages, hardware
failures, programming errors, defects or other vulnerabilities, cyber-attacks, ransomware attacks, malware attacks, computer
viruses, theft, misconduct by employees or other insiders, telecommunications failures, misuse, human errors or other
catastrophic events. While we have controls in place designed to protect our infrastructure, such breaches and threats are
becoming increasingly sophisticated, complex, change frequently and may be difficult to detect. Any such breach, disruption or
similar event that impairs our information technology infrastructure could disrupt normal business operations and affect our
ability to control our generation assets, access retail customer information and limit communication with third parties, which
could have a material adverse effect on us. Any 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.
In addition, we may
experience increased capital and operating costs to implement increased security for our information technology infrastructure
and plants. We cannot provide any assurance that such events and impacts will not be material in the future, and our efforts to
deter, identify and mitigate future breaches may require additional significant capital and may not be successful.
As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its
Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber
assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for
failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential
disruptions from cyber/data and physical security breaches.
Further, our retail business requires us to access, collect, store and transmit sensitive customer data in the ordinary course
of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage,
expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers' license numbers,
social security numbers and bank account information. Our retail business may need to provide sensitive customer data to
vendors and service providers who require access to this information in order to provide services, such as call center operations,
to the retail business. Although we take precautions to protect the sensitive customer data that we are required to collect in
order to conduct our business, if a significant breach of our information technology systems were to occur, the reputation of our
retail business may be adversely affected, customer confidence may be diminished, and our retail business may be subject to
substantial legal or regulatory claims, any of which may contribute to the loss of customers and have a material adverse effect
on us.
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We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear
generation facility.
We own and operate a nuclear generation facility in Glen Rose, Texas (Comanche Peak Facility). The ownership and
operation of a nuclear generation facility involves certain risks. These risks include:
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unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity or other problems;
inadequacy or lapses in maintenance protocols;
the impairment of reactor operation and safety systems due to human error or force majeure;
the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive
materials;
the costs of procuring nuclear fuel;
the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;
terrorist or cybersecurity attacks and the cost to protect against any such attack;
the impact of a natural disaster;
limitations on the amounts and types of insurance coverage commercially available, and
uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear
facilities at the end of their useful lives.
Any prolonged unavailability of the Comanche Peak Facility could have a material adverse effect on our results of
operation, cash flows, financial position and reputation. The following are among the more significant related risks:
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Operational Risk — Operations at any generation facility could degrade to the point where the facility would have to
be shut down.
If such degradations were to occur at the Comanche Peak Facility, the process of identifying and
correcting the causes of the operational downgrade to return the facility to operation could require significant time and
expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments.
Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-
down or reduced availability at the Comanche Peak Facility.
Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply
with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities.
Unless extended, as to which no assurance can be given, the NRC operating licenses for the two licensed operating
units at the Comanche Peak Facility will expire in 2030 and 2033, respectively. Changes in regulations by the NRC,
as well as any extension of our operating licenses, could require a substantial increase in capital expenditures or result
in increased operating or decommissioning costs.
Nuclear Accident Risk — Although the safety record of the Comanche Peak Facility and other nuclear generation
facilities 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.
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The operation and maintenance of power generation facilities and related mining operations are capital intensive and
involve significant risks that could adversely affect our results of operations, liquidity and financial condition.
The operation and maintenance of power generation facilities and related mining operations involve many risks,
including, as applicable, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of
sufficient capital to maintain the facilities, the dependence on a specific fuel source, the inability to transport our product to our
customers in an efficient manner due to the lack of transmission capacity or the impact of unusual or adverse weather
conditions or other natural events, or terrorist attacks, as well as the risk of performance below expected levels of output,
efficiency or reliability, the occurrence of any of which could result in substantial lost revenues and/or increased expenses. A
significant number of our facilities were constructed many years ago. Older generating equipment, even if maintained or
refurbished in accordance with good engineering practices, may require significant capital expenditures to operate at peak
efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and
stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low
wholesale electricity prices that may not justify sustained or year-round operation of all our generation facilities, (b) any
unexpected failure to generate power, including failure caused by equipment breakdown or unplanned outage (whether by order
of applicable governmental regulatory authorities, the impact of weather events or natural disasters or otherwise), (c) damage to
facilities due to storms, natural disasters, wars, terrorist or cyber/data security acts and other catastrophic events and (d) the
passage of time and normal wear and tear. Further, our ability to successfully and timely complete routine maintenance or other
capital projects at our existing facilities is contingent upon many variables and subject to substantial risks. Should any such
efforts be unsuccessful, we could be subject to additional costs or losses and write downs of our investment in the project.
We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety
laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected
events (such as natural disasters or terrorist or cyber/data security attacks). The unexpected requirement of large capital
expenditures could have a material adverse effect on us. Moreover, if we significantly modify a unit, we may be required to
install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under
the new source review provisions of the CAA, which would likely result in substantial additional capital expenditures.
In addition, unplanned outages at any of our generation facilities, whether because of equipment breakdown or otherwise,
typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or
non-performance penalties or require us to incur significant costs as a result of running one of our higher cost units or to
procure replacement power at spot market prices in order to fulfill contractual commitments.
If we do not have adequate
losses, may miss significant
liquidity to meet margin and collateral requirements, we may be exposed to significant
opportunities and may have increased exposure to the volatility of spot markets, which could have a material adverse effect on
us. Further, our inability to operate our generation facilities efficiently, manage capital expenditures and costs, and generate
earnings and cash flow from our asset-based businesses could have a material adverse effect on our results of operations,
financial condition or cash flows. While we maintain insurance, obtain warranties from vendors and obligate contractors to
meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to
cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or
non-performance by contractors or vendors.
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could
have a material adverse effect on Vistra Energy's revenues and results of operations, and Vistra Energy may not have
adequate insurance to cover these risks and hazards. Our employees, contractors, customers and the general public may be
exposed to a risk of injury due to the nature of our operations.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large
pieces of equipment and delivering electricity to transmission and distribution systems.
In addition to natural risks such as
earthquake, flood, lightning, hurricane and wind, other human-made hazards, such as nuclear accidents, dam failure, gas or
other explosions, mine area collapses, fire, structural collapse, machinery failure and other dangerous incidents are inherent
risks in our operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and
destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations.
Further, our employees and contractors work in, and customers and the general public may be exposed to, potentially dangerous
environments at or near our operations. As a result, employees, contractors, customers and the general public are at risk for
serious injury, including loss of life.
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The occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for
substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties.
We maintain an amount of insurance protection that we consider adequate, but we cannot provide any assurance that our
insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject
and, even if we do have insurance coverage for a particular circumstance, we may be subject to a large deductible and
maximum cap. A successful claim for which we are not fully insured could hurt our financial results and materially harm our
financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide any
assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to those presently
available. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of
operations or cash flows.
We may be materially and adversely affected by 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.
As a result of electricity produced for 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 rule, CCR surface 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 flow 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.
We may be materially and adversely affected by the effects of extreme weather conditions and seasonality.
We may be materially affected by weather conditions and our businesses may fluctuate substantially on a seasonal basis as
the weather changes. In addition, we could be subject to the effects of extreme weather conditions, including sustained cold or
hot temperatures, hurricanes, floods, storms, fires, earthquakes or other natural disasters, which could stress our generation
facilities and result in outages, destroy our assets and result in casualty losses that are not ultimately offset by insurance
proceeds, and could require increased capital expenditures or maintenance costs, including supply chain costs.
Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or
damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an
extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or
deliver power where it is needed or limit our ability to source fuel for our plants (including due to damage to rail or natural gas
pipeline infrastructure). Additionally, extreme weather may result in unexpected increases in customer load, requiring our retail
operation to procure additional electricity supplies at wholesale prices in excess of customer sales prices for electricity. These
conditions, which cannot be reliably predicted, could have adverse consequences by requiring us to seek additional sources of
electricity when wholesale market prices are high or to sell excess electricity when market prices are low, which could have a
material adverse effect on us.
36
Risks that are beyond our control, including but not limited to acts of terrorism or related acts of war, natural disaster or
human-made disaster, hostile cyber intrusions or other catastrophic events could have a material adverse effect on our
financial condition, results of operations and cash flows.
Our business, including our generation facilities and the facilities of third parties on which we rely, may be impacted by
an act of war, terrorist activities or other attacks or conflicts, epidemics, pandemics, severe weather conditions and other natural
or human-made disasters, as well as events occurring in response to or in connection with them, which could result in disruption
of our ability to generate, purchase, transmit or distribute electricity and/or natural gas for a significant period of time,
otherwise disrupt our customer operations and/or result in incidents that could result in harmful effects on the environment and
human health, including loss of life. Hostile cyber intrusions, including those targeting information systems as well as
electronic control systems used at the generating plants and for the distribution systems, could severely disrupt business
operations and result in loss of service to customers, as well as significant expense to repair security breaches or system
damage. Any such disruption could result in a significant decrease in revenues, significant additional capital and operating
costs, including costs to implement additional security systems or personnel to purchase electricity and to replace or repair our
assets beyond what could be recovered through insurance policies, higher insurance deductibles, higher premiums and more
restrictive insurance policies, which could have a material adverse effect on our financial condition, results of operations and
cash flows.
Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and
may otherwise have a material adverse effect on us.
Technological advances have improved, and are likely to continue to improve, for existing and alternative methods to
produce and store power, including gas turbines, wind turbines, fuel cells, micro turbines, photovoltaic (solar) cells, batteries
and concentrated solar thermal devices, along with improvements in traditional technologies. Such technological advances
have reduced, and are expected to continue to reduce, the costs of power production or storage to a level that will enable these
technologies to compete effectively with traditional generation facilities. Consequently, the value of our more traditional
generation assets could be significantly reduced as a result of these competitive advances, which could have a material adverse
effect on us. In addition, changes in technology have altered, and are expected to continue to alter, the channels through which
retail customers buy electricity (i.e., self-generation or distributed-generation facilities). To the extent self-generation facilities
become a more cost-effective option for customers, our financial condition, operating cash flows and results of operations could
be materially and adversely affected.
Technological advances in demand-side management and increased conservation efforts have resulted, and are expected
to continue to result, in a decrease in electricity demand. A significant decrease in electricity demand as a result of such efforts
would significantly reduce the value of our generation assets. Certain regulatory and legislative bodies have introduced or are
considering requirements and/or incentives to reduce power consumption. Effective power conservation by our customers
could result in reduced electricity demand or significantly slow the growth in such demand. Any such reduction in demand
could have a material adverse effect on us. Furthermore, we may incur increased capital expenditures if we are required to
increase investment in conservation measures.
We may potentially be affected by emerging technologies that may over time affect change in capacity markets and the
energy industry overall with the inclusion of distributed generation and clean technology.
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. 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 technologies may also affect the financial viability of utility counterparties and
could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on our
financial condition, results of operations and cash flows could be materially adversely affected.
37
The loss of the services of our key management and personnel could adversely affect our ability to successfully operate our
businesses.
Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for
such personnel with many other companies, in and outside of our industry, government entities and other organizations. We
may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to
attract highly qualified new personnel or retain highly qualified existing personnel could have an adverse effect on our ability to
successfully operate our businesses.
We could be materially and adversely impacted by strikes or work stoppages by our unionized employees.
As of December 31, 2019, we had approximately 1,690 employees covered by collective bargaining agreements, of which
approximately 670 are subject to collective bargaining agreements entered into by Dynegy and assumed by us in the Merger.
The terms of all collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-,
coal- and nuclear-fueled generation operation and some of our natural gas-fueled generation operations expire on various dates
between June 2020 and November 2023, 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 of labor strife or
disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or
outages. Our ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate current or future
collective bargaining agreements on favorable terms or at all could have a material adverse effect on us.
Risks Related to Our Structure and Ownership of our Common Stock
Vistra Energy is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to
existing and future liabilities and preferred equity of its subsidiaries.
Vistra Energy is a holding company that does not conduct any business operations of its own. As a result, Vistra Energy's
cash flows and ability to meet its obligations are largely dependent upon the operating cash flows of Vistra Energy's
subsidiaries and the payment of such operating cash flows to Vistra Energy in the form of dividends, distributions, loans or
otherwise. These subsidiaries are separate and distinct legal entities from Vistra Energy and have no obligation (other than any
existing contractual obligations) to provide Vistra Energy with funds to satisfy its obligations. Any decision by a subsidiary to
provide Vistra Energy with funds to satisfy its obligations, including those under the TRA, whether by dividends, distributions,
loans or otherwise, will depend on, among other things, such subsidiary's results of operations, financial condition, cash flows,
cash requirements, contractual prohibitions and other restrictions, applicable law and other factors. The deterioration of income
from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make
other distributions to Vistra Energy.
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.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
38
Item 2. PROPERTIES
Luminant's generation fleet consists of power generation units in six RTOs/ISOs, with the location, RTO/ISO, technology,
primary fuel type, net capacity and ownership interest for each generation facility shown in the table below:
Facility
Ennis
Forney
Hays
Lamar
Midlothian
Odessa
Wise
Coleto Creek
Martin Lake
Oak Grove
DeCordova
Graham
Lake Hubbard
Morgan Creek
Permian Basin
Stryker Creek
Trinidad
Wharton
Comanche Peak
Upton 2
Location
Ennis, TX
Forney, TX
San Marcos, TX
Paris, TX
Midlothian, TX
Odessa, TX
Poolville, TX
Goliad, TX
Tatum, TX
Franklin, TX
Granbury, TX
Graham, TX
Dallas, TX
Colorado City, TX
Monahans, TX
Rusk, TX
Trinidad, TX
Boling, TX
Glen Rose, TX
Upton County, TX
Total ERCOT Segment
Fayette
Hanging Rock
Hopewell
Kendall
Liberty
Ontelaunee
Sayreville
Washington
Kincaid
Miami Fort 7 & 8
Zimmer
Calumet
Dicks Creek
Miami Fort (CT)
Pleasants
Richland
Stryker
Total PJM Segment
Masontown, PA
Ironton, OH
Hopewell, VA
Minooka, IL
Eddystone, PA
Reading, PA
Sayreville, NJ
Beverly, OH
Kincaid, IL
North Bend, OH
Moscow, OH
Chicago, IL
Monroe, OH
North Bend, OH
Saint Marys, WV
Defiance, OH
Stryker, OH
Technology
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
ST
ST
ST
CT
ST
ST
CT
CT
ST
ST
CT
Nuclear
Solar
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
ST
ST
ST
CT
CT
CT
CT
CT
CT
Primary Fuel
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Coal
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Nuclear
Solar
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Coal
Coal
Natural Gas
Natural Gas
Oil
Natural Gas
Natural Gas
Oil
Net Capacity
(MW) (a)
366
1,912
1,047
1,076
1,596
1,054
787
650
2,250
1,600
260
630
921
390
325
685
244
83
2,300
180
18,356
726
1,430
370
1,288
607
600
170
711
1,108
1,020
1,300
380
155
77
388
423
16
10,769
Ownership
Interest (b)
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
50%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
RTO/ISO
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
39
Facility
Bellingham
Bellingham NEA
Blackstone
Casco Bay
Independence
Lake Road
MASSPOWER
Milford
Location
Bellingham, MA
Bellingham, MA
Blackstone, MA
Veazie, ME
Oswego, NY
Dayville, CT
Indian Orchard, MA
Milford, CT
Total NY/NE Segment
Baldwin
Edwards
Newton
Joppa/EEI
Joppa CT 1-3
Joppa CT 4-5
Baldwin, IL
Bartonville, IL
Newton, IL
Joppa, IL
Joppa, IL
Joppa, IL
RTO/ISO
ISO-NE
ISO-NE
ISO-NE
ISO-NE
NYISO
ISO-NE
ISO-NE
ISO-NE
Technology
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
CCGT
MISO
MISO/PJM
MISO/PJM
MISO
MISO
MISO
ST
ST
ST
ST
CT
CT
Primary Fuel
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Coal
Coal
Coal
Natural Gas
Natural Gas
Total MISO Segment
Moss Landing 1 & 2
Oakland
Total CAISO
Total capacity
Moss Landing, CA
Oakland, CA
CAISO
CAISO
CCGT
CT
Natural Gas
Oil
Ownership
Interest (b)
100%
50%
100%
100%
100%
100%
100%
100%
100%
100%
100%
80%
100%
80%
100%
100%
Net Capacity
(MW) (a)
566
157
544
543
1,212
827
281
600
4,730
1,185
585
615
802
165
56
3,408
1,020
165
1,185
38,448
___________
(a) Unit capabilities are based on winter capacity and are reflected at our net ownership interest. We have not included units
that have been retired or are out of operation.
(b) Ownership interest of 100% indicates fee simple ownership of the facility. Ownership of less than 100% indicates the
share of ownership in the facility held by the Company.
Our wholesale commodity risk management group also procures renewable energy credits from renewable generation in
ERCOT to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for renewable
resources from such customers. As of December 31, 2019, Vistra Energy had long-term power purchase agreements to procure
approximately 880 MW of available renewable capacity. These renewable generation sources deliver electricity when
conditions make them available, and, when on-line, they generally compete with baseload units. Because they cannot be relied
upon to meet demand continuously due to their dependence on weather and time of day, these generation sources are
categorized as non-dispatchable and create the need for intermediate/load-following resources to respond to changes in their
output.
Fuel Supply
Nuclear — We 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 capacity. Refueling (nuclear fuel assembly replacement) outages for each unit
are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the
refueling cycle results in the refueling of both units during the same year, which will occur in 2020. While one unit is
undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other
maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. The
Comanche Peak facility operated at a capacity factor of 96%, 101% and 84% in 2019, 2018 and 2017, respectively. The
capacity factor for the year ended December 31, 2017 reflected an unplanned outage at one of the units between June and
August 2017.
We have contracts in place for all of our 2020 and the majority of our 2021 nuclear fuel requirements. We do not
anticipate any significant difficulties in acquiring uranium and contracting for associated conversion, enrichment and
fabrication services in the foreseeable future.
40
Coal/Lignite — Our coal/lignite-fueled generation fleet is comprised of 10 generation facilities totaling 11,115 MW of
generation capacity. Maintenance outages at these units are scheduled during the spring or fall off-peak demand periods. We
meet our fuel requirements at our coal-fueled generation facilities in PJM and MISO with coal purchased from multiple
suppliers under contracts of various lengths and transported to the facilities by either railcar or barges. We meet our fuel
requirements in ERCOT using lignite that we mine at the Oak Grove generation facility, coal purchased and transported by
railcar at the Coleto Creek generation facility and a blend of lignite that we mine and coal purchased and transported by railcar
at our Martin Lake generation facility.
Natural Gas — Our natural gas-fueled generation fleet is comprised of 24 CCGT generating facilities totaling 19,490
MW and 14 peaking generation facilities totaling 5,105 MW. We satisfy our fuel requirements at these facilities through a
combination of spot market and near-term purchase contracts. Additionally, we have near-term natural gas transportation
agreements in place to ensure reliable fuel supply.
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 Energy currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to
provide fuel for its electricity generation facilities. Vistra Energy also owns or leases, and is in the process of reclaiming, two
waste-to-energy surface facilities in Pennsylvania. These mining operations are regulated by the MSHA under the Federal
Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as
the RCT and Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra Energy's mines, on a regular basis,
and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a
citation or order, 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.
41
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Vistra Energy's authorized capital stock consists of 1,800,000,000 shares of common stock with a par value of $0.01 per
share.
Since May 10, 2017, Vistra Energy's common stock has been listed on the NYSE under the symbol "VST". Upon
Emergence and through May 9, 2017, Vistra Energy's common stock was listed on the OTCQX U.S. under the symbol "VSTE".
On April 9, 2018 (Merger Date), pursuant to the Merger Agreement, 94,409,573 shares of Vistra Energy common stock
were issued to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible equity units
and warrants.
As of February 24, 2020, there were 487,734,006 shares of common stock issued and outstanding and 570 stockholders of
record.
In November 2018, we announced that the Board had adopted a 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 2020,
our Board declared a quarterly dividend of $0.135 per share that will be paid in March 2020. 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. Risk Factors and Note 14 to the
Financial Statements
Stock Performance Graph
The performance graph below compares Vistra Energy's cumulative total return on common stock for the period from
May 10, 2017 (the date we were listed on the NYSE) through December 31, 2019 with the cumulative total returns of the S&P
500 Stock Index (S&P 500) and the S&P Utility Index (S&P Utilities). The graph below compares the return in each period
assuming that $100 was invested at May 10, 2017 in Vistra Energy's common stock, the S&P 500 and the S&P Utilities, and
that all dividends were reinvested.
Comparison of Cumulative Total Return
$160
$150
$140
$130
$120
$110
$100
$90
05/10/17
.
12/31/17
.
.
11
12/31/18
.
.
12/31/19
42
Vistra Energy
Corp.
S&P 500
S&P Utilities
Share Repurchase Program
The following table provides information about our repurchase of equity securities that are registered by us pursuant to
Section 12 of the Exchange Act, as amended, during the quarter ended December 31, 2019.
Total Number
of Shares
Purchased
Average
Price Paid
per Share
Total Number of Shares
Purchased as Part of a
Publicly Announced
Program
Maximum Dollar Amount
of Shares that may yet be
Purchased under the
Program (in millions)
October 1 - October 31, 2019
November 1 - November 30, 2019
December 1 - December 31, 2019
674,438
140,200
$
$
— $
26.86
26.55
—
For the quarter ended December 31, 2019
814,638
$
26.81
674,438
140,200
$
$
— $
814,638
$
335
332
332
332
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 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. The share repurchase program has no set expiration date and will
continue until complete or terminated by the Board. At December 31, 2019, $332 million was available for additional
repurchases under the Program. See Note 14 to the Financial Statements for more information concerning the share repurchase
program.
Any purchases of shares of the Company's stock will be made in open market transactions at prevailing market prices, in
privately negotiated transactions, pursuant to plans complying with the Exchange Act or by other means in accordance with
federal securities laws. The actual timing, number and value of shares repurchased under the share repurchase program or
otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation
priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance
with the terms of our debt agreements and the Tax Matters Agreement.
43
Item 6. SELECTED FINANCIAL DATA
VISTRA ENERGY CORP.
SELECTED CONSOLIDATED FINANCIAL INFORMATION
(Millions of Dollars, Except Per Share Amounts
Successor
Predecessor
Operating revenues
Impairment of goodwill
Impairment of long-lived assets
Operating income (loss)
Net income (loss) attributable to Vistra
Energy/the Predecessor (c)
Cash provided by (used in) operating
activities
Net income (loss) per weighted average
share of common stock outstanding —
basic
Net income (loss) per weighted average
share of common stock outstanding —
diluted
Dividend declared per share of common
stock
$
$
$
$
$
$
$
$
$
Year Ended
December 31,
2019 (a)
Year Ended
December 31,
2018 (b)
Year Ended
December 31,
2017
11,809 $
— $
— $
1,993 $
9,144 $
— $
— $
491 $
5,430
Period from
October 3, 2016
through
December 31, 2016
$
1,191
— $
(25) $
$
198
Period from
January 1, 2016
through
October 2, 2016
$
3,973
— $
— $
$
$
— $
— $
$
568
(161)
Year Ended
December 31,
2015
5,370
(2,200)
(2,541)
(4,091)
928 $
(54) $
(254) $
(163)
2,736 $
1,471 $
1,386
$
81
$
$
22,851
$
(4,677)
(238) $
237
1.88 $
(0.11) $
(0.59) $
(0.38)
1.86 $
(0.11) $
(0.59) $
(0.38)
0.50 $
— $
— $
2.32
Successor
At December 31,
2019
2018
2017
2016
Predecessor
At
December 31,
2015
Balance Sheet Information:
Total assets (d)(e)
Property, plant and equipment — net (d)(e)
Goodwill and intangible assets (f)
Long-term debt including current maturities (f)
Short-term borrowings and accounts receivable
securitization program
Borrowings under debtor-in-possession credit facility
Pre-Petition notes, loans and other debt reported as
liabilities subject to compromise (f)
Total stockholders' equity/membership interests
$
$
$
$
$ 26,616
$ 13,914
$
5,301
$ 10,379
$ 26,024
$ 14,612
$
4,561
$ 11,065
$ 14,600
4,820
$
4,437
$
4,423
$
$ 15,167
4,443
$
5,112
$
4,623
$
$
$
$
$
800
$
— $
339
$
— $
— $
— $
— $
— $
15,658
9,349
1,331
19
—
1,425
— $
$
7,959
— $
$
7,863
— $
$
6,342
— $
$
6,597
31,668
(22,884)
___________
(a) For the year ended December 31, 2019, reflects the results of operations acquired in the Crius and Ambit Transactions.
(b) For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.
(c) For the Predecessor period from January 1, 2016 through October 2, 2016, net income includes net gains totaling $22.121
billion related to bankruptcy-related reorganization items including gains on extinguishing claims pursuant to the Plan of
Reorganization.
(d) At December 31, 2018, includes assets acquired in the Merger.
(e) Reflects the impacts of impairment charges related to long-lived assets of $2.541 billion in the year ended December 31,
2015.
(f) As of December 31, 2015, includes both unsecured and under secured obligations incurred prior to the Petition Date, but
excludes pre-petition obligations that were fully secured and other obligations that were allowed to be paid as ordered by
the Bankruptcy Court.
44
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis of our financial condition and results of operations for the years ended December
31, 2019, 2018 and 2017 should be read in conjunction with our condensed consolidated financial statements and the notes to
those statements. Results are impacted by the effects of the Ambit Transaction, the Crius Transaction and the Merger (see Note
2 to the Financial Statements). The discussion and analysis of our financial condition and results of operations for the year
ended December 31, 2017 and for the year ended December 31, 2018 compared to the year ended December 31, 2017 are
included in Item 7. Management's Discussion and Analysis of Financial Condition and Results in our 2018 Form 10-K and is
incorporated herein by reference. Operational results for four facilities retired in late 2019 were recast from the MISO segment
to the Asset Closure segment (see Note 4 to the Financial Statements). The recast is reflected in the results of operations for the
years ended December 31, 2019 and 2018, but the four retired facilities were not owned by Vistra nor did the MISO segment
exist during the year ended December 31, 2017. Therefore, the recast does not impact the comparison of the results of
operations for the years ended December 31, 2018 and December 31, 2017 beyond the recast shown below for the year ended
December 31, 2018.
All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S. dollars unless
otherwise indicated.
Business
Vistra Energy is a holding company operating an integrated power business primarily in markets throughout the U.S.
Through our subsidiaries, we are engaged in competitive energy market activities including power generation, wholesale energy
sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.
Operating Segments
Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-
NE), (v) MISO and (vi) Asset Closure. See Note 20 to the Financial Statements for further information concerning reportable
business segments.
Significant Activities and Events and Items Influencing Future Performance
Acquisitions and Merger
Ambit Transaction — On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly
owned subsidiary of Vistra Energy, completed the acquisition of Ambit (Ambit Transaction). See Note 2 to the Financial
Statements for a summary of the Ambit Transaction and business combination accounting.
Crius Transaction — On July 15, 2019, Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra
Energy, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the
operating business of Crius (Crius Transaction). See Note 2 to the Financial Statements for a summary of the Crius Transaction
and business combination accounting.
Dynegy Merger Transaction — On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated
by the Merger Agreement. See Note 2 to the Financial Statements for a summary of the Merger transaction and business
combination accounting.
Acquisition, Development and Disposition of Generation Facilities
See Note 3 to the Financial Statements for a summary of our solar generation and battery energy storage projects. See
Note 4 to the Financial Statements for a summary of our generation plant retirements in 2018 and 2019.
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 for more information about our dividend program.
45
Share Repurchase Program
In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of
our outstanding common stock may be purchased, and 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. See Note 14 to the Financial Statements for more information
concerning the share repurchase program, including shares repurchased and remaining amounts available under the program.
Debt Activity
We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize
our capital structure, maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities
and/or reduce ongoing interest expense. In 2019, we completed several transactions that we believe, in the aggregate, advanced
all of these goals. See Note 11 to the Financial Statements for details of our long-term debt activity and Note 10 to the
Financial Statements for details of the accounts receivable securitization program.
Capacity Markets
PJM — Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for
each planning year:
2019-2020
2020-2021
2021-2022
Base
CP
CP
CP
$
$
80.00
182.77
80.00
99.77
80.00
80.00
$
100.00
202.77
100.00
119.77
100.00
100.00
$
88.32
188.12
86.04
187.87
76.53
86.04
140.00
195.55
140.00
165.73
171.33
140.00
RTO zone (a)
ComEd zone
MAAC zone
EMAAC zone
ATSI zone
PPL zone
____________
(a)
Planning Year 2020-2021 includes Duke Energy Ohio Kentucky (DEOK) zone which cleared at $130.00 per MW-day.
RTO Zone excluding DEOK Zone was $76.53 per MW-day.
Our capacity sales, net of purchases, aggregated by planning year and capacity type through planning year 2022-2023, are
as follows:
Base auction capacity sold, net (MW)
CP auction capacity sold, net (MW)
Bilateral capacity sold, net (MW)
Total segment capacity sold, net (MW)
Average price per MW-day
2019-2020
2020-2021
2021-2022
2022-2023
837
8,342
160
9,339
—
8,582
200
8,782
—
8,963
200
9,163
—
—
200
200
$
134.43
$
130.04
$
160.55
$
170.00
NYISO — The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our
Independence plant clears, are as follows for each planning period:
Price per kW-month
Summer
2019
$
1.30
$
Winter
2019 - 2020
0.18
46
Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through
bilateral trades. Our capacity sales, aggregated by season through summer 2022, are as follows:
Auction capacity sold (MW)
Bilateral capacity sold (MW)
Total capacity sold (MW)
Average price per kW-month
Winter
2019 - 2020
102
916
1,018
0.86
$
$
Summer
2020
—
955
955
1.82
Winter
2020 - 2021
—
542
542
0.83
$
$
Summer
2021
—
403
403
2.69
Winter
2021 - 2022
—
33
33
1.94
$
ISO-NE — The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are
located, are as follows for each planning year:
Price per kW-month
2019-2020
2020-2021
2021-2022
2022-2023
2023-2024
$
7.03
$
5.30
$
4.63
$
3.80
$
—
Performance incentive rules increase capacity payments for those resources that are providing excess energy or reserves
during a shortage event, while penalizing those that produce less than the required level. We continue to market and pursue
longer term multi-year capacity transactions that extend planning year 2023-2024.
Auction capacity sold (MW)
Bilateral capacity sold (MW)
Total capacity sold (MW)
Average price per kW-month
2019-2020
2020-2021
2021-2022
2022-2023
2023-2024
3,237
71
3,308
6.91
$
3,112
150
3,262
5.35
$
2,939
170
3,109
4.58
$
3,137
95
3,232
3.92
$
$
—
20
20
4.93
MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for
each planning year:
Price per MW-day
2019-2020
$
2.99
MISO capacity sales through planning year 2022-2023 are as follows:
Bilateral capacity sold in MISO (MW)
Base auction capacity sold in PJM (MW)
CP auction capacity sold in PJM (MW)
Total MISO segment capacity sold (MW)
2,128
220
133
2,481
1,974
—
344
2,318
786
—
415
1,201
Average price per kW-month
$
3.81
$
3.52
$
5.06
$
432
—
125
557
5.01
2019-2020
2020-2021
2021-2022
2022-2023
CAISO — Our capacity sales, aggregated by calendar year for 2020 through 2022 for Moss Landing, are as follows:
Bilateral capacity sold (Avg MW)
2020
2021
2022
1,020
—
—
47
Key Operational Risks and Challenges
Following is a discussion of certain key operational risks and challenges facing management and the initiatives currently
underway to manage such challenges. These matters involve risks that could have a material effect on our business, results of
operations, liquidity, financial condition, cash flow, reputation, prospects and the market price for our securities (including our
common stock). See also Item 1A. Risk Factors in this annual report on Form 10-K for additional discussion on risks that could
have a material effect on our results of operations, liquidity, financial condition, cash flow, reputation, prospects and the market
price for our securities (including our common stock).
Natural Gas Price and Market Heat Rate Exposure
The price of power is typically set by natural gas-fueled generation facilities, with wholesale prices generally tracking
increases or decreases in the price of natural gas, 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
extraction; this supply/demand environment has resulted in historically low natural gas prices, and such prices have historically
been volatile. The table below shows the general decline in forward natural gas prices over the last several years (amounts are
per MMBtu.)
Decline of Settled and Forward Natural Gas Prices Since 2008
$9.00
$8.00
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
)
a
(
s
e
c
i
r
P
t
e
k
r
a
M
2008
2009 2010 2011 2012 2013 2014 2015 2016
2017
2018
2019
Period Ending December 31,
Settled
Three Years Forward
________________
(a)
Settled prices represent the average of NYMEX Henry Hub monthly settled prices of financial contracts for the year
ending on the date presented. Forward prices represent the three-year average of NYMEX Henry Hub monthly forward
prices at the date presented. Three-year forward prices are presented as such period is generally deemed to be a liquid
period.
48
In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the
cost of generating power at our nuclear-, lignite- and coal-fueled facilities, which represent a significant portion of our
generation capacity. Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets
increase or decrease in value as wholesale electricity prices change either as a result of changes in natural gas prices or market
heat rates, because of the effect on our operating margins. A persistent 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.
The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate.
Market heat rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of the
marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. Our market heat rate exposure is
impacted by changes in the availability of generation resources, such as additions and retirements of generation facilities, and
mix of generation assets. For example, increasing renewable (wind and solar) generation capacity generally depresses market
heat rates, particularly during periods when total demand is relatively low. However, increasing penetration of renewable
generation capacity may also contribute to greater volatility of wholesale market prices independent of changes in the price of
natural gas, given their intermittent nature. Decreases in market heat rates decrease the value of our generation assets because
lower market heat rates result in lower wholesale electricity prices, and vice versa. In 2018 and prior years, even though market
heat rates generally increased, wholesale electricity prices declined due to the greater effect of falling natural gas prices. Power
price declines in the PJM, NYISO and ISO-NE markets in 2019 relative to 2018 also reflected the impact of lower natural gas
prices. However, in the ERCOT market, wholesale market prices increased in 2019 relative to 2018, as the increase in market
heat rates had a greater effect than the impact of falling natural gas prices.
As a result of our exposure to the variability of natural gas prices and market heat rates, retail sales and hedging activities
are critical to our operating results and maintaining consistent cash flow levels.
Our integrated power generation and retail electricity business provides us opportunities to hedge our generation position
utilizing retail electricity markets as a sales channel. In addition, our approach to managing electricity price risk focuses on the
following:
•
•
•
•
employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial
energy-related contracts intended to partially hedge gross margins;
continuing focus on cost management to better withstand gross margin volatility;
following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the
magnitude and costs of commodity price, liquidity risk and retail demand variability, and
improving retail customer service to attract and retain high-value customers.
We have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices that have
corresponded to declines in natural gas prices. While current and forward natural gas prices are currently depressed, we
continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward
wholesale and retail electricity sales.
Estimated hedging levels for generation volumes in ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO at December 31,
2019 were as follows:
Coal/Nuclear/Renewable Generation:
ERCOT
PJM
MISO
Gas Generation:
ERCOT
PJM
NYISO/ISO-NE
CAISO
49
2020
2021
95 %
100 %
100 %
81 %
84 %
100 %
100 %
71 %
91 %
45 %
10 %
19 %
45 %
34 %
The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and
spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an
assumed heat rate of 7.2 MWh/MMBtu) on realized pretax 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
between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to
spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark
spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation,
related hedges and forward prices as of December 31, 2019.
Balance 2020 (a)
2021
ERCOT:
Coal/Nuclear/Renewable Generation: $2.50/MWh increase in power price
Coal/Nuclear/Renewable Generation: $2.50/MWh decrease in power price
Gas Generation: $1.00/MWh increase in spark spread
Gas Generation: $1.00/MWh decrease in spark spread
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price
PJM:
Coal Generation: $2.50/MWh increase in power price
Coal Generation: $2.50/MWh decrease in power price
Gas Generation: $1.00/MWh increase in spark spread
Gas Generation: $1.00/MWh decrease in spark spread
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price
NYISO/ISO-NE:
Gas Generation: $1.00/MWh increase in spark spread
Gas Generation: $1.00/MWh decrease in spark spread
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price
MISO/CAISO:
Coal Generation: $2.50/MWh increase in power price
Coal Generation: $2.50/MWh decrease in power price
Gas Generation: $1.00/MWh increase in spark spread
Gas Generation: $1.00/MWh decrease in spark spread
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price
___________
(a) Balance of 2020 is from January 1, 2020 through December 31, 2020.
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
8
$
(4) $
12
$
(4) $
3
$
(3) $
2
$
— $
6
$
(5) $
(2) $
2
1
$
$
— $
2
$
(2) $
1
$
— $
— $
— $
1
$
(1) $
37
(29)
37
(30)
(33)
28
5
(2)
28
(26)
(2)
2
8
(7)
—
—
21
(21)
3
(3)
—
—
50
Competitive Retail Markets and Customer Retention
Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch retail electricity providers
for various reasons. Based on numbers of meters and excluding customers acquired in the Ambit and Crius Transactions, our
total retail customer counts increased approximately 2% in 2019, 2% in 2018 and slightly in 2017. Based upon December 31,
2019 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 $50 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:
•
•
• 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
contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and
marketing efforts and to more effectively deploy our direct-sales force; tactical programs we have initiated include
improved customer service, aided by an enhanced customer management system, new product price/service offerings
and a multichannel approach for the small business market.
Exposures Related to Nuclear Asset Outages
Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate
generation capacity of 1,150 MW. As of December 31, 2019, these units represented approximately 6% of our total generation
capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear
generation units experienced an outage at the same time, the unfavorable impact to pretax earnings is estimated (based upon
forward electricity market prices for 2020 at December 31, 2019) 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.
The inherent complexities and related regulations associated with operating nuclear generation facilities result in
environmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review and
regulation by the NRC, covering, among other
things, operations, maintenance, emergency planning, security, and
environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or
operating costs and may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to
comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another
nuclear generation facility could result in the NRC taking action to shut down our Comanche Peak units as a precautionary
measure.
We participate in industry groups and with regulators to keep current on the latest developments in nuclear safety,
operation and maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the
NRC, the Institute of Nuclear Power Operations (INPO) and the Nuclear Energy Institute (NEI). We also apply the knowledge
gained through our continuing investment in technology, processes and services to improve our operations and to detect,
mitigate and protect our nuclear generation assets. Management continues to focus on the safe, reliable and efficient operations
at the facility.
Cyber/Data Security and Infrastructure Protection Risk
A breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal
business operations and affect our ability to control our generation assets, access retail customer information and limit
communication with third parties. Any loss of confidential or proprietary data through a breach could materially affect our
reputation, including our TXU EnergyTM, 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 or impair our ability to
execute on business strategies.
51
We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques.
These groups include, but are not limited to, the U.S. Cyber Emergency Response Team, the National Electric Sector Cyber
Security Organization, the NRC and NERC.
While the Company has not experienced a cyber/data event causing any material operational, reputational or financial
impact, we recognize the growing threat within the general market place and our industry, and are proactively making strategic
investments in our perimeter and internal defenses, cyber/data security operations center and regulatory compliance activities.
We also apply the knowledge gained through industry and government organizations to continuously improve our technology,
processes and services to detect, mitigate and protect our cyber and data assets.
Seasonality
The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results
may fluctuate on a seasonal basis. Typically, demand for and the price of electricity is higher in the summer and winter
seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the
winter. More severe weather conditions such as heat waves or extreme winter weather may make such fluctuations more
pronounced. However, not all regions of the U.S. typically experience extreme weather conditions at the same time, so Vistra
Energy is typically not exposed to the effects of extreme weather in all parts of its business at once. The pattern of this
fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell
electricity.
Application of Critical Accounting Policies
Our significant accounting policies are discussed in Note 1 to the Financial Statements. We follow accounting principles
generally accepted in the U.S. Application of these accounting policies in the preparation of our consolidated financial
statements requires management to make estimates and assumptions about future events that affect the reporting of assets and
liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of
certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might
be reported using different assumptions or estimation methodologies.
Purchase Accounting
On November 1, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the Ambit Transaction. On July
15, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the Crius Transaction. The Ambit Transaction and
Crius Transaction are being accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable
assets acquired and liabilities assumed recorded at their estimated fair values on their acquisition dates.
Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. We
determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date.
The acquired assets that involved the most subjectivity in determining fair value consisted of the customer relationship
intangible assets. The assignment of fair value to the identifiable intangible assets requires judgment. We apply an income-
based valuation methodology in measuring the customer relationships acquired, which include certain assumptions such as
forecasted future cash flows, customer attrition rates, and discount rates. Customer relationship intangibles assets are generally
amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which
the economic benefits are realized over their estimated useful lives.
On the Merger Date, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving
corporation. The Merger was accounted for in accordance with ASC 805, with identifiable assets acquired and liabilities
assumed recorded at their estimated fair values on the Merger Date. Vistra Energy is the acquirer for both federal tax and
accounting purposes. The combined results of operations are reported in our consolidated financial statements beginning as of
the Merger Date. See Note 2 to the Financial Statements.
52
The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant
and equipment and executory contracts, primarily long-term service agreements for maintenance of power plants, a unit-specific
power sales agreement and rail transportation contracts. The fair value of each power plant was estimated using a combination
of an income approach and a market approach. The income approach is the present value of future cash flows over the life of
each power plant that are based on management’s estimates of revenues and operating expenses, and appropriate discount rates.
The estimate of long term prices of electricity and natural gas at each plant location that was used in developing forecasted
revenues for the income approach was especially subjective, because as of the Merger Date, limited market information about
future prices beyond the year 2022 was available. The market valuation method uses prices paid for a reasonably similar asset
by other purchasers in the relevant market, with adjustments relating to any differences between the assets and locations. The
determination of deferred tax assets was complex as it required assessing income tax rules and regulations and proposed
regulations that impose limitations on the future use of acquired net operating losses and other limitations on deductions.
Fresh-Start Reporting
As of the Effective Date, Vistra Energy applied fresh-start reporting under the applicable provisions of ASC 852. Fresh-
start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring
from the consolidated financial statements of the entity that emerges from restructuring, (2) assigning the reorganized value of
the successor entity by measuring all assets and liabilities of the successor entity at fair value, and (3) selecting accounting
policies for the successor entity. The effects from emerging from bankruptcy, including the extinguishment of liabilities, as
well as the fresh start reporting adjustments are reported in the Predecessor's statement of consolidated income (loss). The
consolidated financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the
financial statements of our Predecessor for periods prior to the Effective Date, as those previous periods do not give effect to
any adjustments to the carrying values of assets or amounts of liabilities, nor any differences in accounting policies that were a
consequence of the Plan of Reorganization or the related application of fresh-start reporting.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative
instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under
accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market
accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation
techniques.
Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as
market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net
income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is
dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. Where quoted
market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative
instruments valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity, natural gas
and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights.
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 available 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.
Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections
and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net
income and thus reduce the volatility of net income that can result from fluctuations in fair values. Normal purchases and sales
are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal
course of business and are not subject to mark-to-market accounting if the normal purchase or sale election is made.
Accounting standards also permit an entity to designate certain qualifying derivative contracts in a hedge accounting
relationship, whereby changes in fair value are not recognized immediately in earnings. Vistra Energy does not have derivative
instruments with hedge accounting designations.
53
We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting
arrangements that we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported
separately in the consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on
CME transactions that, beginning in January 2017, are legally characterized as settlement of derivative contracts rather than
collateral.
See Note 16 to the Financial Statements for further discussion regarding derivative instruments.
Accounting for Income Taxes
Vistra Energy files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra
Energy is the corporate parent of the Vistra Energy consolidated group. Pursuant to applicable 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
judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates
and judgments of the timing and probability of recognition of income and deductions by taxing authorities.
In assessing the
likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable
income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes
in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed
tax returns by taxing authorities.
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.
Income tax returns are regularly subject to examination by applicable tax authorities.
Our deferred tax assets were significantly impacted by the TCJA, which reduced the overall federal corporate rate from
35% to 21%. This rate change decreased our overall deferred tax asset balance by approximately $451 million during the year
ended December 31, 2017.
See Notes 1 and 7 to the Financial Statements for further discussion of income tax matters.
Accounting for Tax Receivable Agreement
On the Effective Date, Vistra Energy entered into a tax receivable agreement (the TRA) with a transfer agent. Pursuant to
the TRA, we issued the TRA Rights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA Rights
under the Plan of Reorganization. Vistra Energy reflected the obligation associated with TRA Rights at fair value in the amount
of $574 million as of the Emergence Date related to these future payment obligations. As of December 31, 2019, the TRA
obligation has been adjusted to $455 million. During the year ended December 31, 2019, we recorded a decrease to the
carrying value of the TRA obligation totaling $22 million as a result of adjustments to the timing of forecasted taxable income
and state apportionment due to the expansion of Vistra Energy's state income tax profile, including Dynegy, Crius and Ambit
acquisitions. At December 31, 2019, expected undiscounted payments under the TRA totaled $1.4 billion. The TRA obligation
value is the discounted amount of estimated payments to be made each year under the TRA, based on certain assumptions,
including but not limited to:
•
•
•
•
•
•
the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo
Preferred Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up
among the assets subject thereto;
the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most
of such assets;
a blended federal/state corporate income tax rate in all future years of 23.8%;
future taxable income by year for future years;
the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of
(i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as
a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us
as a result of payments under the TRA in the tax year in which such deductions arise;
a discount rate of 15%, which represented our view at the Emergence Date of the rate that a market participant would
use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of
Emergence, and
54
•
additional states that Vistra Energy now operates in, the relevant tax rates of those states and how income will be
apportioned to those states.
We recognize accretion expense over the life of the TRA Rights liability as the present value of the liability is accreted up
over the life of the liability. This noncash accretion expense is reported in the 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 Rights
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 Obligations (ARO)
As part of business combination accounting, new fair values were established for all AROs assumed in the Merger. A
liability is initially recorded at fair value for 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 assumptions. Specifically, the estimates and assumptions 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
the income statement.
During the year ended December 31, 2017, we recorded additional ARO obligations totaling $112 million primarily
reflecting the acceleration of ARO obligations due to the retirements of our Monticello, Sandow and Big Brown plants.
In
addition, we recorded additional ARO obligations in 2017 totaling $62 million as part of acquiring certain real property through
the Alcoa contract settlement. During the year ended December 31, 2019, we transferred $135 million in ARO obligations to a
third party for remediation. Any remaining unpaid third-party obligation was reclassified to other current liabilities and other
noncurrent liabilities and deferred credits in our consolidated balance sheets.
At December 31, 2019, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled
$1.320 billion and includes an assumption that Vistra Energy receives a license extension of 20 years from the NRC to
continue to operate the Comanche Peak facility. The costs to ultimately decommission that facility are recoverable through the
regulatory rate making process as part of Oncor's delivery fees and therefore do not impact Vistra Energy's earnings.
See Note 21 to the Financial Statements for additional discussion of ARO obligations.
Impairment of Goodwill and Other Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment,
in accordance with
accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances
indicate that their carrying amount may not be recoverable. For our generation assets, possible indications include an
expectation of continuing long-term declines in natural gas prices and/or market heat rates or an expectation that "more likely
than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. The
determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and
may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the
unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and
individual generation units that have varying production or output rates, requires the use of significant
judgments in
determining the existence of impairment indications and the grouping of assets for impairment testing. We generally utilize an
income approach measurement to derive fair values for our long-lived generation assets. The income approach involves
estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity
prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and
forecasted fuel prices. Any significant change to one or more of these factors can have a material impact on the fair value
measurement of our long-lived assets. Additional material impairments related to our generation facilities may occur in the
future if forward wholesale electricity prices decline in the markets in which we operate in or if additional environmental
regulations increase the cost of producing electricity at our generation facilities.
55
Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the TXU EnergyTM,
4Change EnergyTM, Homefield, Dynegy Energy Services, TriEagle Energy, U.S. Gas & Electric, Public Power and Ambit
Energy trade names, are required to be tested for impairment at least annually (as of the Effective Date, we have selected
October 1 as our annual test date) or whenever events or changes in circumstances indicate an impairment may exist, such as
the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public
companies in our industry. Accounting standards allow a company to qualitatively assess if the carrying value of a reporting
unit with goodwill is more likely than not less than the fair value of that reporting unit. If the entity determines the carrying
value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for impairment is
required. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than
not that the fair value of our ERCOT Retail and ERCOT Generation reporting units exceeded its carrying value at October 1,
2019. 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.
Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2019, $1.960 billion of
our goodwill was allocated to our ERCOT Retail reporting unit, $122 million was allocated to our ERCOT Generation
reporting unit and $471 million arose in connection with the Ambit and Crius Transactions and is recorded at the retail segment,
but has not been allocated to any reporting units and is pending completion of the purchase price allocations, at which time
goodwill will be allocated to reporting units. Goodwill impairment testing is performed at the reporting unit level. Under this
goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value
(enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting
unit's assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill
amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied
goodwill amount is written off as an impairment charge.
The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair
value measurements to estimate enterprise values of our reporting units including: internal discounted cash flow analyses
(income approach), and comparable publicly traded company values (market approach). The income approach involves
estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity
prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and
retail sales volume trends, as well as determination of a terminal value. Another key variable in the income approach is the
discount rate, or weighted average cost of capital, applied to the forecasted cash flows. The determination of the discount rate
takes into consideration the capital structure, credit ratings and current debt yields of comparable publicly traded companies as
well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. The
market approach involves using trading multiples of EBITDA of those selected publicly traded companies to derive appropriate
multiples to apply to the EBITDA of our reporting units. Critical judgments include the selection of publicly traded comparable
companies and the weighting of the value metrics in developing the best estimate of enterprise value.
56
RESULTS OF OPERATIONS
Vistra Energy Consolidated Financial Results — Year Ended December 31, 2019 Compared to Year Ended December 31,
2018
Year Ended December 31,
2019
2018
Favorable
(Unfavorable)
$ Change
Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Operating income
Other income
Other deductions
Interest expense and related charges
Impacts of Tax Receivable Agreement
Equity in earnings of unconsolidated investment
Income before income taxes
Income tax (expense) benefit
Net income (loss)
$
$
11,809
(5,742)
(1,530)
(1,640)
(904)
1,993
56
(15)
(797)
(37)
16
1,216
(290)
926
$
$
2,665
(706)
(233)
(246)
22
1,502
9
(10)
(225)
42
(1)
1,317
(335)
982
$
9,144
(5,036)
(1,297)
(1,394)
(926)
491
47
(5)
(572)
(79)
17
(101)
45
(56) $
Eliminations
/ Corporate
and Other
Operating revenues
Fuel, purchased power
costs and delivery fees
Operating costs
Depreciation and
amortization
Selling, general and
administrative expenses
Operating income (loss)
Other income
Other deductions
Interest expense and
related charges
Impacts of Tax Receivable
Agreement
Equity in earnings of
unconsolidated investment
Income (loss) before
income taxes
Income tax expense
Net income (loss)
Year Ended December 31, 2019
Retail
$
6,872
ERCOT
3,993
$
PJM
2,442
$
NY/NE
MISO
$
1,135
$
658
$
Asset
Closure
341
Vistra
Energy
Consolidated
11,809
$
(3,632) $
(267)
(138)
—
(43)
(107)
3
(5)
—
—
—
3,784
(28)
(76)
(86)
(38)
18
(1)
(5,742)
(1,530)
(1,640)
(904)
1,993
56
(15)
(767)
(797)
(37)
—
(37)
16
1,216
(290)
926
(109)
—
(109) $
(825)
(290)
(1,115) $
$
(5,816)
(71)
(1,352)
(714)
(1,111)
(328)
(600)
(101)
(380)
(150)
(292)
(508)
(537)
(208)
(538)
155
—
—
(21)
—
—
134
—
134
$
(79)
1,340
28
(8)
8
—
—
1,368
—
1,368
$
$
(54)
412
—
(1)
(10)
—
4
405
—
405
$
(47)
179
—
—
(3)
—
12
188
—
188
$
(19)
(57)
52
7
—
(4)
—
—
55
—
55
57
Year Ended December 31, 2018
Retail
$
5,597
ERCOT
2,634
$
PJM
1,725
$
NY/NE
MISO
$
817
$
399
$
Asset
Closure
371
Eliminations
/ Corporate
and Other
$
(2,399) $
Vistra
Energy
Consolidated
9,144
(4,126)
(39)
(1,521)
(677)
(917)
(243)
(485)
(74)
(174)
(136)
(286)
(109)
2,473
(19)
(5,036)
(1,297)
(86)
(1,394)
(318)
(416)
(413)
(152)
(424)
690
29
—
(7)
—
—
(90)
(70)
34
(7)
(12)
—
—
712
—
712
$
(55)
—
(55) $
(52)
100
1
—
(8)
—
7
100
—
100
$
(36)
70
—
—
(2)
—
11
79
—
79
$
(9)
(31)
49
—
—
(1)
—
—
48
—
48
—
(39)
(63)
2
(1)
—
—
—
(254)
(285)
(19)
3
(542)
(79)
(1)
(62)
—
(62) $
(923)
45
(878) $
$
(926)
491
47
(5)
(572)
(79)
17
(101)
45
(56)
Operating revenues
Fuel, purchased power
costs and delivery fees
Operating costs
Depreciation and
amortization
Selling, general and
administrative expenses
Operating income (loss)
Other income
Other deductions
Interest expense and
related charges
Impacts of Tax Receivable
Agreement
Equity in earnings of
unconsolidated investment
Income (loss) before
income taxes
Income tax benefit
Net income (loss)
$
In 2019, we focused on safe and reliable operations and produced results during the year that exceeded expectations. Our
performance reflected the stability of our integrated model with the generation fleet operating reliably over the volatile ERCOT
summer while our Retail segment delivered stable pricing and growth in ERCOT residential customer counts. As a result, we
generated significant cash from operations, supporting the Company's ability to fund $713 million of capital expenditures
(including LTSA prepayments, nuclear fuel and development and growth expenditures), invest $880 million in net cash for the
Crius and Ambit Transactions, and advance our balanced capital allocation program, refinancing/repricing approximately $8.3
billion of debt, which lowered interest rates and extended maturities, and returning $899 million to stockholders through share
repurchases and dividends.
Consolidated results increased $982 million to net income of $926 million in the year ended December 31, 2019
compared to the year ended December 31, 2018. The change in results was driven by a $1.076 billion increase in unrealized
gains on hedging transactions, $339 million due to a full year of operations acquired in the Merger, $79 million due to
operations acquired in the Crius Transaction and the Ambit Transaction, and $118 million in lower transition and merger
expenses; partially offset by $246 million increase in depreciation and amortization, $225 million increase in interest expense
and related charges, $335 million increase in income tax expense and $54 million in one-time costs associated with the fourth
quarter 2019 plant retirements.
Interest expense and related charges increased $225 million to $797 million in the year ended December 31, 2019
compared to the year ended December 31, 2018 and reflected a $215 million change in unrealized mark-to-market losses on
interest rate swaps and a $39 million increase in interest paid/accrued reflecting a full year with increased debt associated with
the Merger. Debt extinguishment gains totaled of $21 million in 2019 compared to debt extinguishment losses of $27 million
in 2018. See Note 21 to the Financial Statements.
For the years ended December 31, 2019 and 2018, the Impacts of the TRA totaled expense of $37 million and $79
million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA Obligation.
For the year ended December 31, 2019, income tax expense totaled $290 million and the effective tax rate was 23.8%.
For the year ended December 31, 2018, income tax benefit totaled $45 million and the effective tax rate was 44.6%. See Note 7
to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.
58
Consolidated cash flow from operations produced $2.736 billion in the year ended December 31, 2019 compared to
$1.471 billion produced in the year ended December 31, 2018.
Discussion of Adjusted EBITDA
Non-GAAP Measures — In analyzing and planning for our business, we supplement our use of GAAP financial measures
with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP
financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and
the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more
complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied
upon to the exclusion of GAAP financial measures and are, by definition an incomplete understanding of Vistra Energy and
In addition, non-GAAP financial measures are not standardized;
must be considered in conjunction with GAAP measures.
therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures
having the same or similar names. We strongly encourage investors to review our consolidated financial statements and
publicly filed reports in their entirety and not rely on any single financial measure.
EBITDA and Adjusted EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of
our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis.
Adjusted EBITDA is meant to reflect the operating performance of our segments for the period presented. We define EBITDA
as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define
Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of certain assets, (ii) the impacts
of mark-to-market changes on derivatives, (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.
Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine
our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we
believe they provide useful information for investors.
When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly
comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).
59
Adjusted EBITDA — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Year Ended December 31,
2019
2018
Favorable
(Unfavorable)
$ Change
Net income (loss)
Income tax expense (benefit)
Interest expense and related charges (a)
Depreciation and amortization (b)
EBITDA
Unrealized net (gain) loss resulting from hedging transactions
Generation plant retirement expenses
Fresh start/purchase accounting impacts
Impacts of Tax Receivable Agreement
Non-cash compensation expenses
Transition and merger expenses
Other, net
Adjusted EBITDA, including Odessa earnout buybacks
Odessa earnout buybacks
Adjusted EBITDA
$
$
$
926
290
797
1,713
3,726
(696)
54
30
37
48
115
11
3,325
—
3,325
$
$
$
(56) $
(45)
572
1,472
1,943
380
—
41
79
73
233
(7)
2,742
18
2,760
$
$
982
335
225
241
1,783
(1,076)
54
(11)
(42)
(25)
(118)
18
583
(18)
565
____________
(a)
Includes unrealized mark-to-market net losses on interest rate swaps of $220 million and $5 million for the years ended
December 31, 2019 and 2018, respectively.
(b) Includes nuclear fuel amortization in the ERCOT segment of $73 million and $78 million for the years ended December
31, 2019 and 2018, respectively.
Year Ended December 31, 2019
Net income (loss)
Income tax expense
Interest expense and related
charges (a)
Depreciation and amortization (b)
EBITDA
Unrealized net (gain) loss resulting
from hedging transactions
Generation plant retirement
expenses
Fresh start/purchase accounting
impacts
Impacts of Tax Receivable
Agreement
Non-cash compensation expenses
Transition and merger expenses
Other, net
Adjusted EBITDA
$
21
292
447
278
—
23
—
—
49
10
807
$
Retail
134
—
ERCOT
$ 1,368
—
$
PJM
405
—
10
537
952
NY/NE
188
$
—
$
MISO
55
—
3
208
399
4
19
78
(8)
581
1,941
(591)
(203)
(109)
(30)
—
(3)
—
—
11
12
$ 1,370
$
—
(2)
—
—
6
7
760
$
—
4
—
—
4
9
307
$
12
15
—
—
21
7
103
____________
(a)
(b) Includes nuclear fuel amortization of $73 million in the ERCOT segment.
Includes $220 million of unrealized mark-to-market net losses on interest rate swaps.
60
Asset
Closure
$ (109) $
—
Eliminations
/ Corporate
and Other
Vistra
Energy
Consolidated
926
290
(1,115) $
290
—
—
(109)
—
42
(3)
—
—
—
2
(68) $
$
767
76
18
797
1,713
3,726
(41)
(696)
—
(4)
37
48
24
(36)
46
$
54
30
37
48
115
11
3,325
Year Ended December 31, 2018
NY/NE
79
$
—
$
MISO
48
—
Asset
Closure
$
(62) $
—
Eliminations
/ Corporate
and Other
Vistra
Energy
Consolidated
(56)
(45)
(878) $
(45)
Net income (loss)
Income tax benefit
Interest expense and related
charges (a)
Depreciation and amortization (b)
EBITDA
Unrealized net (gain) loss resulting
from hedging transactions
Fresh start/purchase accounting
impacts
Impacts of Tax Receivable
Agreement
Non-cash compensation expenses
Transition and merger expenses
Other, net
Adjusted EBITDA, including
Odessa earnout buybacks
Odessa earnout buybacks
Adjusted EBITDA
PJM
100
—
8
413
521
42
(1)
—
—
14
16
$
Retail
712
—
ERCOT
$
(55) $
—
7
318
1,037
(206)
26
—
—
1
(13)
845
$
845
$
12
494
451
498
(6)
—
—
9
(2)
950
18
968
2
152
233
40
9
—
—
2
9
1
9
58
(9)
12
—
—
9
10
80
—
—
(62)
—
1
—
—
2
(4)
(63)
542
86
(295)
15
—
79
73
196
(23)
45
592
293
$
592
$
293
$
80
$
(63) $
45
$
572
1,472
1,943
380
41
79
73
233
(7)
2,742
18
2,760
____________
(a)
(b) Includes nuclear fuel amortization of $78 million in the ERCOT segment.
Includes $5 million of unrealized mark-to-market net losses on interest rate swaps.
61
Retail Segment — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Operating revenues:
Revenues in ERCOT
Revenues in Northeast/Midwest
Amortization expense
Other revenues
Total operating revenues
Fuel, purchased power costs and delivery fees:
Purchases from affiliates
Unrealized net gains (losses) on hedging activities with affiliates
Unrealized net gains (losses) on hedging activities
Delivery fees
Other costs (a)
Total fuel, purchased power costs and delivery fees
Net income (loss)
Adjusted EBITDA
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT
Sales volumes in Northeast/Midwest
Total retail electricity sales volumes
Year Ended December 31,
2019
2018
Favorable
(Unfavorable)
Change
$
$
$
$
$
5,061
1,818
(15)
8
6,872
$
$
(3,571)
(305)
19
(1,629)
(330)
(5,816) $
134
807
$
$
4,512
1,123
(26)
(12)
5,597
$
$
(2,846)
218
—
(1,493)
(5)
(4,126) $
712
845
$
$
549
695
11
20
1,275
(725)
(523)
19
(136)
(325)
(1,690)
(578)
(38)
47,345
30,255
77,600
42,992
20,739
63,731
4,353
9,516
13,869
Weather (North Texas average) - percent of normal (b):
Cooling degree days
Heating degree days
96.0 %
113.0 %
103.0 %
112.0 %
____________
(a) For the year ended December 31, 2019, includes $329 million of third-party power purchases, primarily related to the
recent Ambit and Crius Transactions.
(b) Weather data is obtained from Weatherbank, Inc. For the year ended December 31, 2019, normal is defined as the
average over the 10-year period from December 2009 to December 2018. For the year ended December 31, 2018, normal
is defined as the average over the 10-year period from December 2008 to December 2017.
Net income decreased by $578 million to $134 million and Adjusted EBITDA decreased by $38 million to $807 million
in the year ended December 31, 2019 compared to the year ended December 31, 2018.
Unfavorable margins in ERCOT driven by increased power costs and timing of multi-year retail contracts due
to backwardation of power curves
Impact of Crius acquired in July 2019 and Ambit acquired in November 2019
Unfavorable weather in ERCOT
Other driven by higher bad debt expense and other SG&A expense
Change in Adjusted EBITDA
Change in depreciation and amortization expenses driven by reduced amortization of the retail customer
relationship
Unfavorable impact of unrealized net losses on hedging activities
Higher transition and merger and other expenses
Change in Net income
$
$
$
(45)
79
(34)
(38)
(38)
29
(484)
(85)
(578)
62
Generation — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Operating revenues:
Electricity sales
Capacity
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 from
hedging activities
Ancillary and other costs
Fuel, purchased power costs
and delivery fees
ERCOT
PJM
NY/NE
MISO
2019
2018
2019
2018
2019
2018
2019
2018
Year Ended December 31,
$ 1,205
—
2,213
$ 1,289
—
1,829
$ 1,122
162
921
$
$
775
369
628
371
72
132
—
3,993
404
(689)
(198)
(1)
2,634
16
68
153
—
2,442
44
(61)
(33)
3
1,725
703
181
153
—
75
27
(4)
1,135
$
$
582
239
44
$
342
24
285
5
(42)
(3)
(8)
817
(31)
62
(7)
(17)
658
275
25
100
14
(27)
16
(4)
399
(1,186)
(1,367)
(1,073)
(916)
(597)
(479)
(380)
(203)
—
—
16
(182)
(15)
(139)
(1)
(34)
(3)
(8)
8
(1)
(1)
7
(9)
—
—
(6)
2
6
(8)
30
6
(7)
(1,352)
(1,521)
(1,111)
(917)
(600)
(485)
(380)
(174)
Net income (loss)
Adjusted EBITDA
$ 1,368
$ 1,370
$
$
(55) $
405
968
$
760
$
$
100
592
$
$
188
307
$
$
79
293
$
$
55
103
$
$
48
80
Production volumes (GWh):
Natural gas facilities
Lignite and coal facilities
Nuclear facilities
Solar/Battery facilities
Capacity factors:
CCGT facilities
Lignite and coal facilities
Nuclear facilities
Weather - percent of normal (a):
Cooling degree days
Heating degree days
Market pricing
39,433
27,743
19,305
439
35,790
29,151
20,416
344
37,403
14,067
26,431
14,102
18,152
14,605
17,172
12,724
55.0 % 58.8 % 70.1 % 67.8 % 43.8 % 48.2 %
70.4 % 76.9 % 46.1 % 63.2 %
95.8 % 101.3 %
61.5 % 62.3 %
99 %
111 %
100 %
113 %
110 %
99 %
122 %
103 %
100 %
102 %
118 %
103 %
110 %
99 %
134 %
97 %
Average ERCOT North power
price ($/MWh)
$ 35.93
$ 29.96
63
ERCOT
PJM
NY/NE
MISO
2019
2018
2019
2018
2019
2018
2019
2018
Year Ended December 31,
Average NYMEX Henry Hub
natural gas price ($/MMBtu)
$
2.51
$
3.12
Average Market On-Peak Power
Prices ($MWh) (b):
PJM West Hub
AEP Dayton Hub
NYISO Zone C
Massachusetts Hub
Indiana Hub
Northern Illinois Hub
Average natural gas price (c):
TetcoM3 ($/MMBtu)
Algonquin Citygates ($/MMBtu)
$ 30.87
$ 31.02
$ 41.79
$ 40.47
$ 25.90
$ 34.89
$ 37.03
$ 50.11
$
2.39
$
3.69
$
3.17
$
4.84
$ 31.23
$ 28.16
$ 39.01
$ 34.46
____________
(a) Reflects cooling degree days or heating degree days for the region based on Weather Services International (WSI) data.
(b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we
realized.
(c) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
The following table presents changes in net income and Adjusted EBITDA for the year ended December 31, 2019
compared to the year ended December 31, 2018.
Favorable impact related to operations acquired in the Merger (a)
Favorable/(unfavorable) change in revenue net of fuel
Favorable/(unfavorable) change in other operating costs
Favorable/(unfavorable) change in selling. general and
administrative expenses
Other
Change in Adjusted EBITDA
Unfavorable change in depreciation and amortization
Unrealized net gains on hedging activities
Fresh start/purchase accounting impacts
Transition and merger expenses
Generation plant retirement expenses
Other (including interest)
Change in Net income
Year Ended December 31, 2019 Compared to 2018
ERCOT
PJM
NY/NE
MISO
$
— $
438
(39)
9
(6)
402
(87)
1,089
(3)
(2)
—
24
1,423
$
$
$
$
201
(20)
(4)
(4)
(5)
168
(124)
245
1
8
—
7
305
$
$
$
86
(63)
(2)
(3)
(4)
14
(56)
149
5
(2)
—
(1)
109
$
$
$
56
(62)
31
(3)
1
23
(10)
21
(3)
(12)
(12)
—
7
____________
(a)
Impact related to PJM, NY/NE and MISO operations acquired in the Merger are the combined results for the first quarter
of 2019, for which there is no comparable period for 2018 due to the Merger date of April 9, 2018.
The change in ERCOT segment results was driven by a $438 million increase in generation revenue net of fuel reflecting
higher realized power prices, lower natural gas fuel costs and a 1,219 GWh increase in total production volumes, partially
driven by the first quarter production of the generation facilities acquired in the Merger.
The change in PJM segment results was driven by $201 million related to operations in the first quarter of 2019 acquired
in the Merger, partially offset by lower generation in the second through fourth quarters.
64
The change in NY/NE segment results was driven by $86 million related to operations in the first quarter of 2019 acquired
in the Merger, partially offset by lower generation in the second through fourth quarters.
The change in MISO segment results was driven by $52 million related to operations in the first quarter of 2019 acquired
in the Merger and a $30 million decrease in operating costs during the second through fourth quarters, partially offset by a $57
million decrease in revenue net of fuel during the second through fourth quarters reflecting lower realized power prices and
capacity revenue.
Asset Closure Segment — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Selling, general and administrative expenses
Operating income (loss)
Other income
Other deductions
Net income (loss)
Adjusted EBITDA
Production volumes (GWh)
Year Ended December 31,
2019
2018
Favorable
(Unfavorable)
Change
$
$
$
$
341
(267)
(138)
(43)
(107)
3
(5)
(109) $
(68) $
$
371
(286)
(109)
(39)
(63)
2
(1)
(62) $
(63) $
(30)
19
(29)
(4)
(44)
1
(4)
(47)
(5)
7,484
9,759
(2,275)
Results for the Asset Closure segment reflect the retirement of the Coffeen, Duck Creek, Havana and Hennepin plants in
November and December 2019, the retirement of the Northeastern waste coal plant in October 2018, retirement of the Stuart
and Killen plants in May 2018 (acquired in the Merger) and the retirement of the Monticello, Sandow and Big Brown plants in
January and February 2018 (see Note 4 to the Financial Statements). Operating costs for the years ended December 31, 2019
and 2018 included ongoing costs associated with closing these plants.
65
Energy-Related Commodity Contracts and Mark-to-Market Activities
The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31,
2019 and 2018. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $696
million in unrealized net gains for the year ended December 31, 2019 and $380 million in unrealized net losses for the year
ended December 31, 2018, all arising from mark-to-market accounting for positions in the commodity contract portfolio.
Year Ended December 31,
2019
2018
$
Commodity contract net liability at beginning of period
Settlements/termination of positions (a)
Changes in fair value of positions in the portfolio (b)
Acquired commodity contracts (c)
Other activity (d)
Commodity contract net liability at end of period
____________
(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized
gains and losses recognized in the settlement period). The years ended December 31, 2019 and 2018 include reversals of
$3 million and $17 million of previously recorded unrealized gains related to Vistra Energy beginning balances. The
years ended December 31, 2019 and 2018 also include reversals of $124 million and $320 million, respectively, of
previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius Acquisition and
Ambit Acquisition. 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.
(850) $
358
338
(28)
(97)
(279) $
(96)
457
(837)
(454)
80
(850)
$
(b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair
value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
Includes fair value of commodity contracts acquired on the Crius Acquisition, Ambit Acquisition in 2019 and on the
Merger Date in 2018 (see Note 2 to the Financial Statements).
(c)
(d) Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses.
Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits
classified as settlement for certain transactions executed on the CME.
Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair
values at December 31, 2019, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
Source of fair value
Prices actively quoted
Prices provided by other external sources
Prices based on models
Total
Maturity dates of unrealized commodity contract net liability at December 31, 2019
Less than
1 year
1-3 years
4-5 years
Excess of
5 years
Total
$
$
$
74
(269)
29
(166) $
(8) $
2
(22)
(28) $
(4) $
—
(6)
(10) $
— $
—
(75)
(75) $
62
(267)
(74)
(279)
66
FINANCIAL CONDITION
Operating Cash Flows
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 — Cash provided by operating activities
totaled $2.736 billion and $1.471 billion in the years ended December 31, 2019 and 2018, respectively. The favorable change
of $1.265 billion was primarily driven by increased cash from operations reflecting operations acquired in the Merger,
favorable operating results in the ERCOT segment and a decrease in cash used for margin deposits posted with third-parties.
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 $236
million, $139 million and $136 million for the year ended December 31, 2019, 2018 and 2017, respectively. The difference
represented amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent
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.
Investing Cash Flows
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 — Cash used in investing activities totaled
$1,717 million and $101 million in the years ended December 31, 2019 and 2018, respectively. Capital expenditures (including
LTSA prepayments, nuclear fuel purchases and growth and development expenditures) totaled $713 million and $530 million
in the years ended December 31, 2019 and 2018, respectively. Cash used in investing activities in the year ended December 31,
2019 also reflected $880 million of net cash paid in the Crius and Ambit Transactions and $125 million of net purchases of
environmental allowances. Cash used in investing activities in the year ended December 31, 2018 also reflected $445 million
of cash acquired in the Merger.
In the years ended December 31, 2019 and 2018, capital expenditures, including LTSA prepayments, nuclear fuel
purchases and growth and development expenditures, consisted of:
Investments in generation and mining facilities
Nuclear fuel purchases
LTSA prepayments
Information technology and other corporate investments (a)
Growth and development expenditures
Capital expenditures, including LTSA prepayments, nuclear fuel purchases and growth
and development expenditures
___________
(a)
Includes Comanche Peak repair costs.
Financing Cash Flows
Year Ended December 31,
2019
2018
333 $
89
122
65
104
713 $
208
118
100
70
34
530
$
$
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 — Cash used in financing activities totaled
$1.237 billion and $2.723 billion in the years ended December 31, 2019 and 2018, respectively. The decrease in cash used in
financing activities was driven by:
•
•
•
•
the issuance of $5.7 billion principal amount of Vistra Operations senior secured and unsecured notes in 2019
compared to the issuance of $1.0 billion principal amount of Vistra Operations senior unsecured notes in 2018;
the amendment to the Vistra Operations Credit Facilities in 2018, including the repayment of $500 million in term
loans;
$350 million in net borrowings under the Revolving Credit Facility in 2019, and;
$107 million decrease in cash paid for share repurchases in 2019 compared to 2018,
partially offset by:
•
the net repayment of approximately $3.1 billion of term loans under the Vistra Operations Credit Facilities in 2019;
67
•
•
•
cash tender offers and early redemptions to purchase senior unsecured notes assumed in the Merger of $3.0 billion in
2019 compared to $2.5 billion in 2018;
$243 million of cash dividends paid to stockholders in 2019, and
$228 million net decrease in incremental borrowings under the account receivable securitization program.
Debt Activity
See Note 11 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.
Available Liquidity
The following table summarizes changes in available liquidity for the year ended December 31, 2019:
Cash and cash equivalents
Vistra Operations Credit Facilities — Revolving Credit Facility
Total available liquidity
December 31, 2019
300
$
1,426
1,726
$
December 31, 2018
636
$
1,135
1,771
$
$
$
Change
(336)
291
(45)
The $45 million decrease in available liquidity in the year ended December 31, 2019 was primarily driven by $880
million of net cash paid in the Crius and Ambit Transactions, $656 million in cash paid for share repurchases, $713 million of
capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), $387 million
principal amount of outstanding 7.625% Senior Notes due 2024 redeemed in November 2019, $243 million in dividends paid to
shareholders, $203 million in debt tender offer and other financing fees and the $70 million redemption of mandatorily
redeemable preferred stock in PrefCo, partially offset by cash from operations, $500 million of new Alternate LOC Facilities
and $225 million of additional available capacity under the Revolving Credit Facility.
Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our
anticipated cash requirements, including those related to our capital allocation initiatives, through at least the next 12 months.
Our operational cash flows tend to be seasonal and weighted toward the second half of the year.
Capital Expenditures
Estimated capital expenditures and nuclear fuel purchases for 2020 are expected to total approximately $935 million and
include:
•
•
•
•
$532 million for investments in generation and mining facilities;
$85 million for nuclear fuel purchases;
$3 million for information technology and other corporate investments, and
$315 million for growth and development expenditures.
Liquidity Effects of Commodity Hedging and Trading Activities
We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of
the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash,
letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 11 to the Financial
Statements for discussion of the Vistra Operations Credit Facilities.
Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take
into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin
posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is
generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin
based on various factors, including market depth, volatility and credit quality, which may be in the form of cash, letters of
credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either
used for working capital and other business purposes, including reducing borrowings under credit facilities, or is required to be
deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect
to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In
such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the
event the cash was not restricted.
68
At December 31, 2019, we received or posted cash and letters of credit for commodity hedging and trading activities as
follows:
•
•
•
•
$202 million in cash has been posted with counterparties as compared to $361 million posted at December 31, 2018;
$8 million in cash has been received from counterparties as compared to $4 million received at December 31, 2018;
$1.150 billion in letters of credit have been posted with counterparties as compared to $1.185 billion posted at
December 31, 2018, and
$17 million in letters of credit have been received from counterparties as compared to $12 million received at
December 31, 2018.
Income Tax Payments
In the next 12 months, we do not expect to make federal income tax payments due to Vistra Energy's use of NOL
carryforwards. We expect to make approximately $26 million in state income tax payments, offset by $14 million in state tax
refunds, and no TRA payments in the next 12 months. In addition, we expect to receive approximately $100 million in AMT
refundable credits in the next 12 months.
In February 2019, we received a refund of $21 million related to Vistra Energy's 2017 federal tax return. In December
2019, we received a refund of $94 million related to alternative minimum tax credits claimed on Vistra Energy's 2018 tax
return. For the year ended December 31, 2019, there were no federal income tax payments, $39 million in state income tax
payments and $2 million in TRA payments.
Capitalization
Our capitalization ratios consisted of 56% and 58% long-term debt (less amounts due currently) and 44% and 42%
shareholders' equity at December 31, 2019 and 2018, respectively. Total long-term debt (including amounts due currently) to
capitalization was 57% and 58% at December 31, 2019 and 2018, respectively.
Financial Covenants
The Credit Facilities Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely
during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving
letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first-lien
net leverage ratio not exceed 4.25 to 1.00. As of December 31, 2019, we were in compliance with this financial covenant.
See Note 11 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit
Facilities.
Collateral Support Obligations
The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the
RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is
effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities)
that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation
of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits
have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory
obligations by the RCT, and includes cost contingency amounts.
The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer
deposits, if necessary. Under these rules, at December 31, 2019, Vistra Energy has posted letters of credit in the amount of $38
million with the PUCT, which is subject to adjustments.
The RTOs/ISOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the
markets operated by those RTOs/ISOs. Under these rules, Vistra Energy has posted collateral support totaling $316 million in
the form of letters of credit, $10 million in the form of a surety bond and $8 million of cash at December 31, 2019 (which is
subject to daily adjustments based on settlement activity with the RTOs/ISOs).
69
Material Cross Default/Acceleration Provisions
Certain of our contractual arrangements contain provisions that could result in an event of default if there was a failure
under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments
due. Such provisions are referred to as "cross default" or "cross acceleration" provisions.
A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an
aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a
default would allow the lenders to accelerate the maturity of outstanding balances (approximately $3.05 billion at December 31,
2019, including $350 million of cash borrowings under the Revolving Credit Facility) under such facilities.
Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are
secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross default
provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a
threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under
these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its
applicable subsidiary) and require all outstanding obligations under such agreement to be settled.
Under (i) the Vistra Operations' Senior Unsecured Indentures and the Senior Secured Indenture, 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, or (ii) with respect to the Vistra Energy Senior Unsecured Indentures (except with respect to the Consent
Senior Notes), a default under any document evidencing indebtedness for borrowed money by Vistra Energy 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 $100 million or more, may result in a cross default under the Vistra Operations Senior Unsecured Notes,
the Senior Secured Notes, the Vistra Energy Senior Unsecured Notes (except with respect to the Consent Senior 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 applicable borrower or issuer, as the case may be, and the applicable
Guarantor Subsidiaries party thereto.
Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions
whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of
borrowings in excess of thresholds, which may vary by contract.
The Receivables Facility contains a cross default provision. The cross default provision applies, among other instances, if
Vistra Operations, the performance guarantor, fails to make a payment of principal or interest on any indebtedness that is
outstanding in a principal amount of at least $300 million, or, in the case of TXU Energy, the originator and servicer, in a
principal amount of at least $50 million, or if other events occur or circumstances exist under such indebtedness which give rise
to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If
this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables
Facility may be terminated.
Under the Alternate LOC Facilities, 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 Alternate LOC
Facilities.
70
Contractual Obligations and Commitments
The following table summarizes the amounts and related maturities of our contractual cash obligations at December 31,
2019. See Notes 11 and 13 to the Financial Statements for additional disclosures regarding debt and noncancellable purchase
obligations.
Contractual Cash Obligations:
Debt – principal (a)
Debt – interest
Operating and finance leases
Long-term service and maintenance contracts
Obligations under commodity purchase and services
agreements (b)
Total contractual cash obligations
$
$
Less Than
One Year
One to
Three
Years
Three to
Five
Years
More
Than Five
Years
$
273
502
29
167
$
136
967
42
324
$
2,076
954
36
313
$
7,949
912
82
1,975
Total
10,434
3,335
189
2,779
1,378
2,349
$
733
2,202
$
709
4,088
$
974
11,892
$
3,794
20,531
___________
(a)
Includes $2.7 billion principal amount of term loans under the Vistra Operations Credit Facility, $3.1 billion principal
amount of Vistra Operations senior secured notes, $3.6 billion principal amount of Vistra Operations senior unsecured
notes, $747 million principal amount of Vistra Energy senior unsecured notes and $287 million principal amount of other
long-term debt, including forward capacity agreements and equipment financing agreements. Excludes short-term
borrowings, the accounts receivable securitization program and unamortized premiums, discounts and debt costs.
(b) Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and
nuclear related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the
year-end 2019 price for all periods except where contractual price adjustment or index-based prices are specified.
The following are not included in the table above:
•
•
•
•
•
•
the TRA obligation (see Note 8 to the Financial Statements);
asset retirement obligations (see Note 21 to the Financial Statements);
arrangements between affiliated entities and intercompany debt (see Note 19 to the Financial Statements);
individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with
one counterparty that are more than $1 million on an aggregated basis have been included);
contracts that are cancellable without payment of a substantial cancellation penalty, and
employment contracts with management.
Guarantees
See Note 13 to the Financial Statements for discussion of guarantees.
OFF–BALANCE SHEET ARRANGEMENTS
As of December 31, 2019, we have no off-balance sheet arrangements, other than certain investments in energy and
energy-related entities that are accounted for under the equity method of accounting which are not expected to have any
material impact on our financial condition, results of operations or liquidity.
COMMITMENTS AND CONTINGENCIES
See Note 13 to the Financial Statements for discussion of commitments and contingencies.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to the Financial Statements for discussion of changes in accounting standards.
71
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk that in the normal course of business we may experience a loss in value due to changes in market
conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to
market risk is affected by several factors, including the size, duration and composition of our energy and financial portfolio, as
well as the volatility and liquidity of markets.
Risk Oversight
We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive
energy business within limitations established by senior management and in accordance with overall risk management policies.
Interest rate risk is managed centrally by our treasury function. Market risks are monitored by risk management groups that
operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These
techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from
changes in market conditions and include, but are not limited to, position reporting and review, Value at Risk (VaR)
methodologies and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and
approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of
transaction capture, market price validation and reporting, and portfolio valuation and reporting.
Commodity Price Risk
Our business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-
related products it markets or purchases. We actively manage the portfolio of generation assets, fuel supply and retail sales load
to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot
fully manage the long-term value impact of structural declines or increases in natural gas and power prices.
In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-
term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with
customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We
continuously monitor the valuation of identified risks and adjust positions based on current market conditions.
VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio
under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified
confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical
and projected market prices and volatilities.
Parametric processes are used to calculate VaR and are considered by management to be the most effective way to
estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires
a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period (i.e., the time
necessary for management action, such as to liquidate positions) and (iii) historical estimates of volatility and correlation data.
The table below details a VaR measure related to various portfolios of contracts.
VaR for Underlying Generation Assets and Energy-Related Contracts — This measurement estimates the potential loss
in value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence
level and an assumed holding period of 60 days for a forward period through December 2020 for the year ended December 31,
2019 and December 2019 for the year ended December 31, 2018.
Month-end average VaR
Month-end high VaR
Month-end low VaR
Year Ended December 31,
2019
2018
$
$
$
263
520
103
$
$
$
182
267
65
The increase in the VaR risk measures in 2019 was primarily driven by an increase in volatility in ERCOT as compared
to the prior year.
72
Interest Rate Risk
The following table provides information concerning our financial instruments at December 31, 2019 and 2018 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 further discussion of these financial instruments.
Expected Maturity Date
2020
2021
2022
2023
2024
2019
Total
Carrying
Amount
2019
Total
Fair
Value
2018
Total
Carrying
Amount
2018
Total
Fair
Value
There-
after
(millions of dollars, except percentages)
Long-term debt,
including current
maturities (a):
Variable rate
debt amount
Average interest
rate (b)
Debt swapped to
fixed (c):
$
27
$
27
$
27
$
27
$
27
$
2,565
$ 2,700
$ 2,717
$ 5,813
$ 5,599
3.55 % 3.55 % 3.55 % 3.55 % 3.55 %
3.55 % 3.55 %
4.55 %
$
720
$
3,000
$ 6,720
$ 7,717
Notional amount $ — $ — $ — $ 3,000
Average pay
rate
Average receive
rate
3.77 % 3.77 % 3.77 % 4.10 % 4.75 %
3.54 % 3.54 % 3.54 % 3.43 % 3.21 %
Debt swapped to
variable (c):
Notional amount $ — $ — $ — $
Average pay
rate
Average receive
rate
3.54 % 3.54 % 3.54 % 3.47 % 3.23 %
3.21 % 3.21 % 3.21 % 3.22 % 3.30 %
4.77 %
3.21 %
3.21 %
3.30 %
700
$
720
$
700
$ 2,120
$
—
___________
(a) Unamortized premiums, discounts and debt issuance costs are excluded from the table.
(b) The weighted average interest rate presented is based on the rates in effect at December 31, 2019.
(c)
Interest rate swaps have maturity dates through July 2026.
At December 31, 2019, 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 $9 million taking
into account the interest rate swaps 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 further discussion
of this exposure.
Bankruptcies — We are party to (i) certain gas transportation agreements with PG&E and (ii) a long-term resource
adequacy contract with PG&E in connection with the Moss Landing battery storage project, which was approved by the
California Public Utilities Commission (CPUC) in November 2018. PG&E filed for Chapter 11 bankruptcy protection in
January 2019. On October 15, 2019, PG&E filed a motion in its bankruptcy proceeding requesting approval of the assumption
of the resource adequacy contract. In early November 2019, the bankruptcy court approved the assumption motion subject to
the CPUC approving the terms of the amendment. The CPUC approved the terms of the amendment on January 22, 2020 so the
resource adequacy contract as amended is now assumed and fully enforceable against PG&E.
73
As of December 31, 2019, we had no outstanding accounts receivable from PG&E and accordingly, we have not recorded
a reserve related to the pre-petition receivables. While our assumptions and conclusions may change, we could have future
impairment losses or be required to seek alternative, higher-cost fuel transportation methods if any of the terms of the gas
transportation agreements are not honored by PG&E or the gas transportation agreements are rejected through the bankruptcy
process.
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
$1.407 billion at December 31, 2019.
At December 31, 2019, Retail segment credit exposure totaled $1.024 billion, including $1.008 billion of trade accounts
receivable and $16 million related to derivative assets. Cash deposits and letters of credit held as collateral for these receivables
totaled $53 million, resulting in a net exposure of $971 million. We believe the risk of material loss (after consideration of bad
debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for
uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical
experience, market or operational conditions and changes in the financial condition of large business customers.
At December 31, 2019, aggregate ERCOT, PJM, NY/NE and MISO segments credit exposure totaled $383 million
including $316 million related to derivative assets and $67 million of trade accounts receivable, after taking into account master
netting agreement provisions but excluding collateral impacts.
Including collateral posted to us by counterparties, our net ERCOT, PJM, NY/NE and MISO segments exposure was $382
million substantially all of which is with investment grade customers as seen in the following table that presents the distribution
of credit exposure at December 31, 2019. 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
$
$
347
36
383
$
$
Credit
Collateral
Net
Exposure
— $
1
1
$
347
35
382
Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented an
aggregate $204 million, or 53%, of the total net exposure. We view exposure to these counterparties to be within an acceptable
level of risk tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, the counterparties'
market role and deemed creditworthiness and the importance of our business relationship with the counterparties. An event of
default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available
liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to
us.
Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market
in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is
favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.
74
FORWARD-LOOKING STATEMENTS
This report and other presentations made by us contain "forward-looking statements." All statements, other than
statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise,
that address activities, events or developments that may occur in the future, including (without limitation) such matters as
activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy,
business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power
generation assets, market and industry developments and the growth of our businesses and operations (often, but not always,
through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated,"
"should," "may," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we
believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such
forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion under
Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in
this annual report on Form 10-K and the following important factors, among others, that could cause our actual results to differ
materially from those projected in or implied by such forward-looking statements:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
▪
the actions and decisions of judicial and regulatory authorities;
prohibitions and other restrictions on our operations due to the terms of our agreements;
prevailing federal, state and local governmental policies and regulatory actions, including those of the legislatures and
other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the TRE, the public
utility commissions of states and locales in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the
RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the MSHA and the
CFTC, with respect to, among other things:
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
allowed prices;
industry, market and rate structure;
purchased power and recovery of investments;
operations of nuclear generation facilities;
operations of fossil-fueled generation facilities;
operations of mines;
acquisition and disposal of assets and facilities;
development, construction and operation of facilities;
decommissioning costs;
present or prospective wholesale and retail competition;
changes in federal, state and local tax laws, rates and policies, including additional regulation, interpretations,
amendments, or technical corrections to the TCJA;
changes in and compliance with environmental and safety laws and policies, including the Coal Combustion
Residuals 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 have a negative financial effect;
legal and administrative proceedings and settlements;
general industry trends;
economic conditions, including the impact of an economic downturn;
weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of
sabotage, wars or terrorist or cybersecurity threats or activities;
our ability to collect trade receivables from counterparties;
our ability to attract and retain profitable customers;
our ability to profitably serve our customers;
restrictions on competitive retail pricing or direct-selling businesses;
adverse publicity associated with our retail products or direct selling businesses, including our ability to address the
marketplace and regulators regarding our compliance with applicable laws;
changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
75
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
impact of disruptions in U.S. and
sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation and
storage thereof;
changes in the ability of vendors to provide or deliver commodities as needed;
beliefs and assumptions about the benefits of state- or federal-based subsidies to our market competition, and the
corresponding impacts on us, including if such subsidies are disproportionately available to our competitors;
the effects of, or changes to, market design and the power and capacity procurement processes in the markets in
which we operate;
changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets;
our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat
rates and interest rates;
population growth or decline, or changes in market supply or demand and demographic patterns, particularly in
ERCOT, MISO and PJM;
our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance
incentives in ISO-NE;
efforts to identify opportunities to reduce congestion and improve busbar power prices;
access to adequate transmission facilities to meet changing demands;
changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
changes in operating expenses, liquidity needs and capital expenditures;
commercial bank market and capital market conditions and the potential
international credit markets;
access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and
refinancing efforts, including availability of funds in capital markets;
our ability to maintain prudent financial leverage;
our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our
debt obligations;
our ability to implement our growth strategy, including the completion and integration of mergers, acquisitions and/or
joint venture activity and identification and completion of sales and divestitures activity;
competition for new energy development and other business opportunities;
inability of various counterparties to meet their obligations with respect to our financial instruments;
counterparties' collateral demands and other factors affecting our liquidity position and financial condition;
changes in technology (including large scale electricity storage) used by and services offered by us;
changes in electricity transmission that allow additional power generation to compete with our generation assets;
our ability to attract and retain qualified employees;
significant changes in our relationship with our employees, including the availability of qualified personnel, and the
potential adverse effects if labor disputes or grievances were to occur or changes in laws or regulations relating to
independent contractor status;
changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits,
pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure
under ERISA;
hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses
resulting from such hazards;
the impact of our obligations under the TRA;
our ability to optimize our assets through targeted investment in cost-effective technology enhancements and
operations performance initiatives;
our ability to effectively and efficiently plan, prepare for and execute expected asset retirements and reclamation
obligations and the impacts thereof;
our ability to successfully complete the integration of businesses acquired by Vistra Energy and our ability to
successfully capture the full amount of projected operational and financial synergies relating to such transactions, and
actions by credit rating agencies.
Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we
undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is
made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not
possible for us to predict them. In addition, we may be unable to assess the impact of any such event or condition or the extent
to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those
contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking
statements.
76
INDUSTRY AND MARKET INFORMATION
Certain industry and market data and other statistical information used throughout this report are based on independent
industry publications, government publications, reports by market research firms or other published independent sources,
including certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of
states in which we operate and NYMEX. We did not commission any of these publications, reports or other sources. Some
data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent
sources listed above. Industry publications, reports and other sources generally state that they have obtained information from
sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that
each of these studies, publications, reports and other sources is reliable, we have not independently investigated or verified the
information contained or referred to therein and make no representation as to the accuracy or completeness of such information.
Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions
were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used
throughout this report involve risks and uncertainties and are subject to change based on various factors.
77
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Vistra Energy Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Vistra Energy Corp. and subsidiaries (the "Company") as of
December 31, 2019 and 2018, 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, 2019, and the related notes (collectively referred to as the "financial statements"). In
our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of
December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in
Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 28, 2020 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 applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
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 financial 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 – Refer to Notes 1 and 8 to the financial statements
Critical Audit Matter Description
The Company has a tax receivable agreement (TRA) obligation that requires the Company to make annual payments to the
TRA rights holders based on cash savings in income tax resulting from a step up in the tax basis of certain assets upon
emergence from bankruptcy in 2016. The carrying value of the TRA obligation is based on the discounted amount of forecasted
payments to the TRA rights holders. Determining the carrying value of the TRA obligation requires management to make
significant estimates and assumptions in preparing its forecast of taxable income for a period of approximately 40 years.
Changes to either the estimated timing or amount of expected TRA payments impact the carrying value of the obligation. As of
December 31, 2019, the carrying value of the TRA obligation totaled $455 million.
Given the significant judgements made by management to estimate the TRA obligation, performing audit procedures to
evaluate the reasonableness of management’s estimate and assumptions related to the estimated future taxable income required
a high degree of auditor judgement and an increased extent of effort, including the need to involve our income tax specialists.
78
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to estimated future taxable income included the following, among others:
• We tested the effectiveness of controls over management’s determination of the TRA obligation carrying amount,
including controls over developing the estimated future taxable income.
• With the assistance of our income tax specialists, we evaluated the following elements in testing management’s
estimated future 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 Company press releases as well as in analyst and industry reports for the
Company.
• We assessed the consistency of future taxable income with evidence obtained in other areas of the audit.
Fair Value Measurements – Level 3 Derivative Assets and Liabilities – Refer to Notes 1 and 15 to the financial
statements
Critical Audit Matter Description
The Company has numerous derivative assets and liabilities. The fair values of a portion of these derivative instruments are
based on complex proprietary models and/or unobservable inputs. These derivative financial instruments include (1) forward
sales and purchases of electricity, natural gas, and coal; (2) electricity, natural gas, and coal options; and (3) financial
transmission rights. Under accounting principles generally accepted in the United States of America, these financial instruments
are generally classified as Level 3 assets or liabilities. As of December 31, 2019, the fair value of the Level 3 derivative assets
and liabilities totaled $239 million and $313 million, respectively.
Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of Level 3 assets and
liabilities, performing audit procedures to evaluate the appropriateness of these models and inputs 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 Matter Was Addressed in the Audit
Our audit procedures related to the proprietary models and unobservable inputs used by management to estimate the fair value
of Level 3 derivative assets and liabilities included the following, among others:
• We tested the effectiveness of controls over derivative asset and liability valuations, including controls related to
price verification of illiquid price curves.
• We assessed the consistency by which management has applied significant unobservable valuation assumptions.
• We obtained the Company’s complete listing of derivative assets and liabilities and related fair values as of December
31, 2019, to confirm our understanding of the types of instruments outstanding and performed sensitivity analysis to
understand the most significant assumptions impacting fair value.
• With the assistance of our energy commodity fair value specialists, we developed independent estimates of the fair
value of a sample of Level 3 derivative instruments and compared our estimates to the Company’s estimates.
79
Asset Retirement Obligations – Mining Land Reclamation – Refer to Notes 1 and 21 to the financial statements
Critical Audit Matter Description
The Company recognizes asset retirement obligations associated with legal, regulatory, contractual, or constructive retirement
requirements of tangible long-lived assets. These liabilities primarily relate to nuclear generation plant decommissioning, land
reclamation related to lignite mining, removal of coal/lignite-fueled plant ash treatment facilities and generation plant disposal
costs. The estimate of the asset retirement obligations requires management to make significant estimates and assumptions.
Specifically, the estimates and assumptions 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, the Company utilizes 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 the statement of operations. Changes in these assumptions
could have a significant impact on the carrying amount of the asset retirement obligations. The asset retirement obligation
balance related to mining land reclamation obligations was $410 million as of December 31, 2019.
Given the complexity and the significant judgements made by management, including internally developed volumetric models
to estimate the mining land reclamation asset retirement obligation, performing audit procedures to evaluate the reasonableness
of management’s estimates and assumptions required a high degree of auditor judgment and an increased extent of effort,
including the need to involve our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the mining land reclamation obligation included the following, among others:
• We tested the effectiveness of controls over the accounting for asset retirement obligations, including those over
management’s development of cost estimates.
• We evaluated management’s ability to accurately develop cost estimates by comparing actual
results to
management’s prior cost estimates.
• We evaluated the completeness of management’s cost estimates by comparing management’s cost estimates to
regulatory agency filings.
• With the assistance of our environmental specialists, we evaluated management’s cost estimates by assessing the
impact of any changes in the regulatory environment and testing the mathematical accuracy and reasonableness of
management’s volumetric model.
• We selected a sample of cost estimates for mining land reclamation and performed the following:
–
Evaluated management’s cost estimates for mining land reclamation by performing corroborating inquiries
with the Company’s project managers and engineers and comparing the estimates to management’s
workplans, engineering specifications, and supplier contracts.
– With the assistance of our environmental specialists, we evaluated the reasonableness of the costs estimates
for mining land reclamation by:
◦
◦
Evaluating the reasonableness of the methodology used to develop the cost estimate.
Testing the source information underlying the determination of the cost estimates for mining land
reclamation and the mathematical accuracy of the calculations.
– Developed a range of independent estimates and compared those to the cost estimates developed by
management.
80
Acquisitions, Merger Transaction and Business Combination Accounting — Crius Energy Trust — Retail Customer
Relationship Intangible Asset — Refer to Notes 2 and 6 to the financial statements
Critical Audit Matter Description
The Company completed the acquisition of Crius Energy Trust for $400 million on July 15, 2019. The Company accounted for
the acquisition under the acquisition method of accounting for business combinations. Accordingly, the purchase price was
allocated to the assets acquired and liabilities assumed based on their respective fair values, including customer relationship
intangible assets of $223 million. Management estimated the fair value of the customer relationship intangible asset using an
income-based valuation methodology, specifically a discounted cash flow analysis. The fair value determination of the
customer relationship intangible assets required management
to make significant estimates and assumptions related to
forecasted future cash flows, customer attrition rates and discount rates.
We identified the customer relationship intangible assets for the acquired entity as a critical audit matter because of the
significant estimates and assumptions management made to estimate the fair value of these assets. This required a high degree
of auditor judgment and an increased extent of effort, including the involvement of our fair value specialists, when performing
audit procedures to evaluate the reasonableness of management’s forecasts of future cash flows and the customer attrition rates
and discount rates used in the valuation.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the forecasts of future cash flows and the customer attrition rates and discount rates used in
valuing the customer relationship intangible assets for the acquired business included the following, among others:
• We tested the effectiveness of controls over the valuation of the customer relationship intangible assets, including
management’s controls over the development of the key judgments including forecasts of future cash flows and
customer attrition rates and discount rates.
• We assessed the reasonableness of fiscal year 2019 forecasted cash flows by comparing them to the actual 2019 cash
flows of the acquired business.
• We assessed the reasonableness of the forecasts of future cash flows by comparing margins and attrition rates to the
acquired business’ most recent historical periods.
• We performed sensitivity analyses of the significant assumptions of forecasted future cash flows, customer attrition
rates, and discount rates used in the valuation model to evaluate the change in fair value resulting from changes in the
significant assumptions.
• With the assistance of our fair value specialists, we evaluated the reasonableness of the (1) valuation methodology;
(2) customer attrition rate by testing the mathematical accuracy of the rate used and comparing it to historical
customer attrition data and actual customer attrition subsequent to the acquisition date; and (3) discount rate, which
included testing the source information underlying the determination of the discount rates, testing the mathematical
accuracy of the calculations, and developing a range of independent estimates and comparing those to the discount
rates selected by management.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 28, 2020
We have served as the Company's auditor since 2002.
81
VISTRA ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(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 assets
Operating income
Other income (Note 21)
Other deductions (Note 21)
Interest expense and related charges (Note 21)
Impacts of Tax Receivable 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 loss attributable to noncontrolling interest
Net income (loss) attributable to Vistra Energy
Weighted average shares of common stock outstanding:
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,
2019
2018
2017
11,809
(5,742)
(1,530)
(1,640)
(904)
—
1,993
56
(15)
(797)
(37)
16
1,216
(290)
926
2
928
$
$
$
9,144
(5,036)
(1,297)
(1,394)
(926)
—
491
47
(5)
(572)
(79)
17
(101)
45
(56)
2
(54) $
5,430
(2,935)
(973)
(699)
(600)
(25)
198
37
(5)
(193)
213
—
250
(504)
(254)
—
(254)
494,146,268
499,935,490
504,954,371
504,954,371
427,761,460
427,761,460
1.88
1.86
$
$
(0.11) $
(0.11) $
(0.59)
(0.59)
$
$
$
$
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
Net income (loss)
Other comprehensive income (loss), net of tax effects:
Year Ended December 31,
2019
2018
2017
$
926
$
(56) $
(254)
Effects related to pension and other retirement benefit obligations (net of
tax benefit of $4, $2 and $6)
Adoption of new accounting standard
Total other comprehensive income (loss)
Comprehensive income (loss)
Comprehensive loss attributable to noncontrolling interest
Comprehensive income (loss) attributable to Vistra Energy
$
(8)
—
(8)
918
2
920
$
(6)
1
(5)
(61)
2
(59) $
(23)
—
(23)
(277)
—
(277)
See Notes to the Consolidated Financial Statements.
82
VISTRA ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Cash flows — operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to cash provided by operating
activities:
Depreciation and amortization
Deferred income tax expense (benefit), net
Unrealized net (gain) loss from mark-to-market valuations of
commodities
Unrealized net (gain) loss from mark-to-market valuations of interest
rate swaps
Impairment of long-lived assets (Note 4)
Impacts of Tax Receivable Agreement (Note 8)
Change in asset retirement obligation liability
Asset retirement obligation accretion expense
Bad debt expense
Stock-based compensation
Other, net
Changes in operating assets and liabilities:
Accounts receivable — trade
Inventories
Accounts payable — trade
Commodity and other derivative contractual assets and liabilities
Margin deposits, net
Accrued interest
Accrued taxes
Accrued employee incentive
Alcoa contract settlement (Note 4)
Tax Receivable Agreement payment (Note 8)
ARO settlement
Major plant outage deferral
Other — net assets
Other — net liabilities
Cash provided by operating activities
Cash flows — investing activities:
Capital expenditures, including LTSA prepayments
Nuclear fuel purchases
Development and growth expenditures (Note 3)
Ambit acquisition (net of cash acquired) (Note 2)
Crius acquisition (net of cash acquired) (Note 2)
Cash acquired in the Merger (Note 2)
Odessa acquisition (Note 3)
Proceeds from sales of nuclear decommissioning trust fund securities
(Note 21)
Investments in nuclear decommissioning trust fund securities (Note 21)
Proceeds from sales of environmental allowances
83
Year Ended December 31,
2019
2018
2017
$
926
$
(56) $
(254)
1,876
281
(696)
220
—
37
(48)
53
82
47
(12)
(88)
(44)
(221)
98
170
80
(4)
1
—
(2)
(121)
(19)
(22)
142
2,736
(520)
(89)
(104)
(506)
(374)
—
—
431
(453)
197
1,533
(62)
380
5
—
79
(27)
50
55
73
37
(207)
61
90
(80)
(221)
(105)
(64)
40
—
(16)
(100)
(22)
73
(45)
1,471
(378)
(118)
(34)
—
—
445
—
252
(274)
1
835
418
145
(29)
25
(213)
112
60
39
—
30
7
22
(30)
(1)
146
(10)
33
(24)
238
(26)
(35)
(66)
4
(40)
1,386
(114)
(62)
(190)
—
—
—
(355)
252
(272)
1
VISTRA ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Purchases of environmental allowances
Other, net
Cash used in investing activities
Cash flows — financing activities:
Issuances of long-term debt (Note 11)
Repayments/repurchases of debt (Note 11)
Net borrowings under accounts receivable securitization program (Note
10)
Borrowings under Revolving Credit Facility (Note 11)
Repayments under Revolving Credit Facility (Note 11)
Debt tender offer and other debt financing fees (Note 11)
Stock repurchase (Note 14)
Dividends paid to stockholders (Note 14)
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
$
See Notes to the Consolidated Financial Statements.
Year Ended December 31,
2019
2018
2017
(322)
23
(1,717)
6,507
(7,109)
111
650
(300)
(203)
(656)
(243)
6
(1,237)
(218)
693
475
$
(5)
10
(101)
1,000
(3,075)
339
—
—
(236)
(763)
—
12
(2,723)
(1,353)
2,046
693
$
(3)
16
(727)
—
(191)
—
—
—
(8)
—
—
(2)
(201)
458
1,588
2,046
84
VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
Year Ended December 31,
2019
2018
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash (Note 21)
Trade accounts receivable — net (Note 21)
Inventories (Note 21)
Commodity and other derivative contractual assets (Note 16)
Margin deposits related to commodity contracts
Prepaid expense and other current assets
Total current assets
Restricted cash (Note 21)
Investments (Note 21)
Investment in unconsolidated subsidiary (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:
Short-term borrowings (Note 11)
Accounts receivable securitization program (Note 10)
Long-term debt due currently (Note 11)
Trade accounts payable
Commodity and other derivative contractual liabilities (Note 16)
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
Total current liabilities
Long-term debt, less amounts due currently (Note 11)
Operating lease liabilities (Note 12)
Commodity and other derivative contractual liabilities (Note 16)
Accumulated deferred income taxes (Note 7)
Tax Receivable Agreement obligation (Note 8)
Asset retirement obligations (Note 21)
Other noncurrent liabilities and deferred credits (Note 21)
Total liabilities
85
$
$
$
$
$
$
300
147
1,365
469
1,333
202
298
4,114
28
1,537
124
44
13,914
2,553
2,748
136
1,066
352
26,616
350
450
277
947
1,529
8
1
200
151
141
14
506
4,574
10,102
41
396
2
455
2,097
989
18,656
636
57
1,087
412
730
361
152
3,435
—
1,250
131
—
14,612
2,068
2,493
109
1,336
590
26,024
—
339
191
945
1,376
4
10
182
77
156
—
345
3,625
10,874
—
270
10
420
2,217
741
18,157
VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
Commitments and Contingencies (Note 13)
Total equity (Note 14):
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000)
(shares outstanding: December 31, 2019 — 487,698,111; December 31, 2018 —
493,215,309)
Treasury stock, at cost (shares: December 31, 2019 — 41,043,224; December 31, 2018
— 32,815,783)
Additional paid-in-capital
Retained deficit
Accumulated other comprehensive income (loss)
Stockholders' equity
Noncontrolling interest in subsidiary
Total equity
Total liabilities and equity
See Notes to the Consolidated Financial Statements.
Year Ended December 31,
2019
2018
5
5
(973)
9,721
(764)
(30)
7,959
1
7,960
26,616
$
(778)
10,107
(1,449)
(22)
7,863
4
7,867
26,024
$
86
VISTRA ENERGY CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)
Common
Stock
Treasury
Stock
Additional
Paid-In
Capital
Retained
Deficit
Accumulated
Other
Comprehensive
Income (Loss)
Total
Stockholders'
Equity
Noncontrolling
Interest in
Subsidiary
Total
Equity
Balances at December 31, 2016 $
4
$ — $ 7,742
$(1,155) $
6
$
6,597
$
— $ 6,597
Effects of stock-based
compensation
Net loss
Pension and OPEB liability
— change in funded status
Other
—
—
—
—
—
—
—
—
23
—
—
—
—
(254)
—
(1)
—
—
(23)
—
23
(254)
(23)
(1)
—
—
—
—
23
(254)
(23)
(1)
Balances at December 31, 2017 $
4
$ — $ 7,765
$(1,410) $
(17) $
6,342
$
— $ 6,342
Stock and stock
compensation awards issued
in connection with the
Merger
Stock repurchases
Effects of stock-based
compensation
Tangible equity units
acquired
Warrants acquired
Net loss
Adoption of new accounting
standards
Pension and OPEB liability
— change in funded status
Investment by noncontrolling
interest
Other
Balances at December 31, 2018 $
Stock repurchases
Shares issued for tangible
equity unit contracts
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 status
Other
1
—
—
—
—
—
—
—
—
—
5
—
—
—
—
—
—
—
—
—
(778)
1,901
—
—
—
—
—
—
—
—
—
72
369
2
—
—
—
—
(2)
—
—
—
—
—
(54)
16
—
—
(1)
—
—
—
—
—
—
1
(6)
—
—
1,902
(778)
72
369
2
(54)
17
(6)
—
(3)
$ (778) $10,107
—
(641)
$(1,449) $
—
(22) $
—
$
7,863
(641)
446
(446)
—
—
—
—
—
—
62
—
—
—
—
(2)
—
—
928
(243)
(2)
—
2
—
—
—
—
—
(8)
—
—
62
928
(243)
(2)
(8)
—
—
—
—
—
—
(2)
—
—
6
—
4
—
—
—
(2)
—
—
—
(1)
1,902
(778)
72
369
2
(56)
17
(6)
6
(3)
$ 7,867
(641)
—
62
926
(243)
(2)
(8)
(1)
Balances at December 31, 2019 $
5
$ (973) $ 9,721
$ (764) $
(30) $
7,959
$
1
$ 7,960
See Notes to the Consolidated Financial Statements.
87
VISTRA ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business
References in this report to "we," "our," "us" and "the Company" are to Vistra Energy and/or its subsidiaries, as apparent
in the context. See Glossary for defined terms.
Vistra Energy is a holding company operating an integrated retail and generation business primarily in markets throughout
the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including power generation,
wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.
Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-
NE), (v) MISO and (vi) Asset Closure. The PJM, NY/NE and MISO segments were established on the Merger Date to reflect
markets served by businesses acquired in the Merger. See Note 20 for further information concerning reportable business
segments.
Ambit Transaction
On November 1, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the acquisition of Ambit (Ambit
Transaction). Because the Ambit Transaction closed on November 1, 2019, Vistra Energy's consolidated financial statements
and the notes related thereto do not include the financial condition or the operating results of Ambit and its subsidiaries prior to
November 1, 2019. See Note 2 for a summary of the Ambit Transaction.
Crius Transaction
On July 15, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the acquisition of the equity interests
of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). Because the
Crius Transaction closed on July 15, 2019, Vistra Energy's consolidated financial statements and the notes related thereto do not
include the financial condition or the operating results of Crius and its subsidiaries prior to July 15, 2019. See Note 2 for a
summary of the Crius Transaction.
Dynegy Merger Transaction
On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement.
Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the
surviving corporation. Because the Merger closed on April 9, 2018, Vistra Energy's consolidated financial statements and the
notes related thereto do not include the financial condition or the operating results of Dynegy prior to April 9, 2018. See Note 2
for a summary of the Merger transaction and business combination accounting.
Basis of Presentation
The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the
audited financial statements included in our 2018 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 Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of
assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value
measurements, estimates of expected obligations, judgments related to the potential timing of events and other estimates. In the
event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to
reflect more current information.
88
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities utilizing
instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the
instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging
activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses. This
recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to-
market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or
liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting
arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported
separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME
transactions that are legally characterized as settlement of derivative contracts rather than collateral. When derivative
instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and
derivative assets and liabilities are reversed. See Notes 15 and 16 for additional information regarding fair value measurement
and commodity and other derivative contractual assets and liabilities. A commodity-related derivative contract may be
designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal
course of business.
If designated as normal, the derivative contract is accounted for under the accrual method of accounting
(not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative
instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash
flow or fair value hedges if certain conditions are met. At December 31, 2019 and 2018, there were no derivative positions
accounted for as cash flow or fair value hedges.
We report commodity hedging and trading results as revenue, fuel expense or purchased power in the consolidated
statements of operations depending on the type of activity. Electricity hedges, financial natural gas hedges and trading
activities are primarily reported as revenue. Physical or financial hedges for coal, diesel or uranium, along with physical natural
gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swap
transactions are reported in the consolidated statements of operations in interest expense.
Revenue Recognition
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes
delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not
billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the
last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are
adjusted when actual usage is known and billed.
We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are
not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO or RTO,
ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response
available for system reliability requirements, and certain other electricity sales contracts. See Note 5 for detailed descriptions of
revenue from contracts with customers. See Derivative Instruments and Mark-to-Market Accounting for revenue recognition
related to derivative contracts.
Advertising Expense
We expense advertising costs as incurred and include them within SG&A expenses. Advertising expenses totaled $49
million, $46 million and $44 million for the year ended December 31, 2019, 2018 and 2017, respectively.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of
impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less
than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying
value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market
valuations, if applicable.
89
Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their
estimated useful lives based on the expected realization of economic effects. See Note 6 for details of intangible assets with
finite lives, including discussion of fair value determinations.
Goodwill and Intangible Assets with Indefinite Lives
As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally
allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining
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 capitalized and reported as a component of our property, plant and equipment in our consolidated balance
sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel,
purchased power costs and delivery fees in our consolidated statements of operations.
Major Maintenance Costs
Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over
the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are
charged to expense as incurred and reported as operating costs in our consolidated statements of operations.
Defined Benefit Pension Plans and OPEB Plans
On the Merger Date, Vistra Energy assumed the pension and OPEB plans that Dynegy had provided to certain of its
eligible employees and retirees. The excess of the benefit obligations over the fair value of plan assets was recognized as a
liability. See Note 2 for additional information regarding the Merger.
Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement
of such employee from the company. Pension benefits are offered to eligible employees under collective bargaining
agreements based on either a traditional defined benefit formula or a cash balance formula. Effective January 1, 2017, the
OPEB plan was amended to discontinue the life insurance benefits for active employees. Costs of pension and OPEB plans are
dependent upon numerous factors, assumptions and estimates.
See Note 17 for additional information regarding pension and OPEB plans.
Stock-Based Compensation
Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. The fair
value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model.
Forfeitures are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line
basis over the requisite service period for the entire award. See Note 18 for additional information regarding stock-based
compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as "pass through" items on the consolidated balance sheets with no effect on the
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 liability to the taxing jurisdiction in other current liabilities in our consolidated statements of
operations).
90
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and gross receipt 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 gross receipt taxes, but we
are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense
in our consolidated statements of operations.
Income Taxes
On the Merger Date, Vistra Energy and Dynegy effected a merger transaction that for tax purposes was treated as a tax-
In general, all of Dynegy's tax basis and attributes
free reorganization in which Vistra Energy survived as the parent entity.
were transferred to Vistra Energy, including approximately $4.5 billion of utilizable NOLs and refundable AMT tax credits.
Investment tax credits are accounted for under the deferral method, which resulted in a reduction to the basis of the Upton
2 solar and battery storage facility of $2 million and $78 million and a corresponding increase in the deferred tax assets in 2019
and 2018, respectively.
Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as
required under accounting rules. See Note 7.
We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 7.
Tax Receivable Agreement (TRA)
The Company accounts for its obligations under the TRA as a liability in our consolidated balance sheets (see Note 8).
The carrying value of the TRA obligation represents the discounted amount of projected payments under the TRA. The
projected payments are based on certain assumptions, including but not limited to (a) the federal and state corporate income tax
rates and (b) estimates of our taxable income in the current and future years. Our taxable income takes into consideration the
current federal tax code and reflects our current estimates of future results of the business.
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective
interest method and the interest rate estimated at the Emergence Date. Changes in the estimated amount of this obligation
resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and are included
on our consolidated statements of operations under the heading of Impacts of Tax Receivable Agreement.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss
contingencies are recorded when management determines that it is probable that a liability has been incurred and that such
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 for a discussion of
contingencies.
Such determinations are subject
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of
three months or less are considered cash equivalents.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. See Note 21 for more details
regarding restricted cash.
91
Property, Plant and Equipment
Property, plant and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or
at cost for capital improvements and individual facilities developed (see Notes 2 and 3). Significant improvements or additions
to our property, plant and equipment that extend the life of the respective asset are capitalized at cost, while other costs are
expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor,
including payroll-related costs.
Interest related to qualifying construction projects and qualifying software projects is
capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 21.
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.
Asset Retirement Obligations (ARO)
A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation
associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in
which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is
also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated
useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation
related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for
the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets.
Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related
asset as information becomes available. Changes in estimates related to assets that have been retired or for which capitalized
costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 21.
Inventories
Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is
valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects,
respectively. Fuel stock and natural gas in storage are reported at the lower of cost (on a weighted average basis) or market.
We expect to recover the value of inventory costs in the normal course of business. See Note 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.
Unconsolidated Investments
We use the equity method of accounting for investments in affiliates over which we exercise significant influence. Our
share of net income (loss) from these affiliates is recorded to equity in earnings (loss) of unconsolidated investment in the
consolidated statements of operations. See Note 21.
Noncontrolling Interest
Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own. EEI is our
consolidated subsidiary that owns a coal facility in Joppa, Illinois. This noncontrolling interest is classified as a component of
equity separate from stockholders' equity in the consolidated balance sheets.
92
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is
recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capital.
See Note 14.
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.
Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent
our obligation to make lease payments arising from the lease. ROU assets and lease liabilities 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
secured incremental borrowing rate based on the information available at the lease commencement date to determine the present
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. At
adoption, we elected the practical expedient which permits us to not reassess under the new standard our prior conclusion about
lease classification and initial direct costs. We have also elected the practical expedient to not separate lease and non-lease
components for a majority of the lease asset classes. We have also elected the hindsight practical expedient to determine the
lease term.
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.
Adoption of New Accounting Standards
Leases — On January 1, 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 comparative information has not
been restated and continues to be reported under the accounting standards in effect for those periods. We expect the impact of
the adoption of the new lease standard to be immaterial to our net income on an ongoing basis. The impact of adopting the new
lease standard primarily relates to recognition of lease liabilities and ROU assets for all leases classified as operating leases.
Under the new lease standard, each ROU asset will be amortized over the lease term and liability settled at the end of the lease
term.
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.
93
As of January 1, 2019, the cumulative effect of the changes made to our consolidated balance sheet for the adoption of the
new lease standard was as follows:
Impact on consolidated balance sheet:
Assets
Property, plant and equipment — net
Operating lease right-of-use assets
Prepaid expense and other current assets
Accumulated deferred income taxes
Liabilities
Other current liabilities
Operating lease liabilities
Identifiable intangible liabilities
Other noncurrent liabilities and deferred credits
Equity
Retained deficit
December 31,
2018
Adoption of New
Lease Standard
January 1,
2019
$
$
14,612
—
152
1,336
345
—
401
340
$
15
70
(2)
1
(1)
109
(36)
14
14,627
70
150
1,337
344
109
365
354
(1,449)
(2)
(1,451)
See Note 12 for the disclosures required by the new lease standard.
Changes to the Disclosure Requirements for Defined Benefit Plans — In August 2018, the Financial Accounting
Standards Board (FASB) issued ASU 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans. The ASU
removes disclosure requirements for (a) the amounts in accumulated other comprehensive income expected to be recognized as
components of net periodic benefit cost over the next fiscal year, (b) related party disclosures about the amount of future annual
benefits covered by insurance and annuity contracts and significant transactions between the employer or related parties and the
plan and (c) the effects of a one-percentage-point change in assumed health care cost trend rates on the aggregate of the service
and interest cost components of net periodic benefit costs and benefit obligation for postretirement health care benefits. The
ASU requires new disclosures for (a) the weighted-average interest crediting rates for cash balance plans and other plans with
promised interest crediting rates and (b) an explanation of the reasons for significant gains and losses related to changes in the
benefit obligation for the period. We adopted this ASU in the fourth quarter of 2018, and the updated disclosures are included
in Note 17.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income — In February 2018, the
FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The
ASU permits the reclassification of income tax effects of the TCJA on items within accumulated other comprehensive income
(AOCI) to retained earnings. We adopted this ASU in the fourth quarter of 2018, and the impact was additional tax expense to
AOCI of $1 million with the offset to retained deficit (see Note 7).
Revenue from Contracts with Customers — On January 1, 2018, we adopted Accounting Standards Update (ASU)
2014-09, Revenue from Contracts with Customers (Topic 606) and all related amendments (new revenue standard) using the
modified retrospective method for all contracts outstanding at the time of adoption. We recognized the cumulative effect of
initially applying the revenue standard as an adjustment to the opening balance of retained deficit. The comparative
information has not been restated and continues to be reported under the accounting standards in effect for those periods. The
impact of the adoption of the revenue standard was immaterial and we expect the adoption to continue to be immaterial to our
net income on an ongoing basis. Our retail energy charges and wholesale generation, capacity and contract revenues will
continue to be recognized when electricity and other services are delivered to our customers. The impact of adopting the
revenue standard primarily relates to the deferral of acquisition costs associated with retail contracts with customers that were
previously expensed as incurred. Under the revenue standard, these amounts are capitalized and amortized over the expected
life of the customer.
94
Statement of Cash Flows — In November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230):
Restricted Cash. The ASU requires restricted cash to be included in the cash and cash equivalents and a reconciliation between
the change in cash and cash equivalents and the amounts presented on the balance sheet. We adopted the standard on January
1, 2018. The ASU modified our presentation of our consolidated statements of cash flows, and retrospective application to
comparative periods presented was required. For the year ended December 31, 2017, our consolidated statements of cash flows
previously reflected a source of cash of $186 million, reported as changes in restricted cash, that is now reported in net change
in cash, cash equivalents and restricted cash. See the consolidated statements of cash flows and Note 21 for disclosures related
to the adoption of this accounting standard.
Changes in Accounting Standards
In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes (Topic 740). The ASU
will be effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. The ASU enhances and
simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the
approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition
of deferred tax liabilities for outside basis differences. The new guidance also simplifies 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-up in the tax
basis of goodwill. We are currently evaluating the impact of this ASU on our financial statements, but we do not expect it to
have a material impact upon adoption.
In August 2018, the FASB issued ASU 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement.
The ASU will be effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. The ASU
removes disclosure requirements for (a) the reasons for transfers between Level 1 and Level 2, (b) the policy for timing of
transfers between levels and (c) the valuation processes for Level 3. The ASU will require new disclosures around (a) the
changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value
measurements held at the end of the reporting period and (b) the range and weighted average of significant unobservable inputs
used to develop Level 3 fair value measurements. We do not expect the ASU to have a material impact on our financial
statements.
In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud
Computing Arrangement That Is a Service Contract. The ASU will be effective for fiscal years beginning after December 15,
2019 and early adoption is permitted. The ASU requires a customer in a cloud hosting arrangement that is a service contract to
determine which implementation costs to capitalize and which costs to expense based on the project stage of the
implementation. The ASU also requires the customer to expense the capitalized implementation costs over the term of the
hosting arrangement. The customer is required to apply the existing impairment and abandonment guidance on the capitalized
implementation costs. We do not expect the ASU to have a material impact on our financial statements.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses. The ASU requires organizations to
measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current
conditions and reasonable and supportable forecasts. The ASU will be effective for fiscal years beginning after December 31,
2019. We do not expect the ASU to have a material impact on our financial statements.
95
2.
ACQUISITIONS, MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING
Ambit Transaction
On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of
Vistra Energy, completed the Ambit Transaction. Ambit is an energy retailer selling both electricity and natural gas products to
residential and small business customers in 17 states. Vistra Energy funded the purchase price of $555 million (including cash
acquired and net working capital) using cash on hand. All of Ambit's outstanding debt was repaid from the purchase price at
closing and not assumed by Vistra Energy.
Crius Transaction
On July 15, 2019 (Crius Acquisition Date), Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra
Energy, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the
operating business of Crius. Crius is an energy retailer selling both electricity and natural gas products to residential and small
business customers in 19 states. Vistra Energy funded the purchase price of $400 million (including $382 million for
outstanding trust units) using cash on hand. See Note 11 for discussion of debt assumed in the Crius Transaction.
Ambit and Crius Business Combination Accounting
We believe the Ambit Transaction has (i) augmented Vistra Energy's existing retail marketing capabilities with additional
direct selling capability and a proprietary technology platform, (ii) reduced risk and aided expansion into higher margin
channels by improving Vistra Energy's match of its generation to load profile due to a high degree of overlap with Vistra
Energy'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 efficiencies, particularly via Ambit's retail electric portfolio.
We believe the Crius Transaction has (i) reduced risk and aided expansion into higher margin channels by improving
Vistra Energy's match of its generation to load profile due to a high degree of overlap with Vistra Energy's generation fleet with
Crius' approximately 10 TWh of annual electricity load, (ii) established a platform for growth by leveraging Vistra Energy's
existing retail marketing capabilities and Crius' experienced team and (iii) enhanced the integrated value proposition through
collateral and transaction efficiencies, particularly via Crius' retail electric portfolio.
The Ambit and Crius Transactions are being accounted for in accordance with ASC 805, Business Combinations (ASC
805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Ambit and Crius
Acquisition Dates, respectively. The combined results of operations are reported in our consolidated financial statements
beginning as of the respective Ambit and Crius Acquisition Dates. 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 capital was valued using available 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).
•
96
The following table summarizes the preliminary allocation of the purchase price to the fair value amounts recognized for
the assets acquired and liabilities assumed related to the Ambit and Crius Transactions as of the Ambit and Crius Acquisition
Dates, respectively. The Ambit Transaction purchase price was $555 million (including cash acquired and net working capital),
and the Crius Transaction purchase price was $400 million. The purchase price allocations are ongoing and are dependent upon
final valuation determinations, which have not been completed. The preliminary values included below represent our current
best estimates for accumulated deferred income taxes, identifiable intangible assets, net working capital and long-term debt.
During the three months ended December 31, 2019, we updated the preliminary purchase price allocation of the Crius
Transaction reported as of September 30, 2019 with revised valuation estimates by decreasing net working capital by $37
million, decreasing identifiable intangible assets by $2 million, increasing goodwill by $52 million, decreasing other noncurrent
assets by $2 million, decreasing identifiable intangible liabilities by $36 million, increasing other noncurrent liabilities and
deferred credits by $1 million and changing accumulated deferred income taxes from an asset of $36 million to a liability of $9
million. The purchase price allocations are preliminary and each of the values included below may change materially based
upon the receipt of more detailed information, additional analyses and completed valuations. The final purchase price
allocation is expected to be completed no later than the second quarter of 2020 for the Crius Transaction and no later than the
third quarter of 2020 for the Ambit Transaction.
Ambit and Crius Transactions Preliminary Purchase Price Allocations
Cash and cash equivalents and restricted cash
Net working capital
Identifiable intangible assets
Goodwill
Commodity and other derivative contractual assets
Other noncurrent assets
Total assets and net working capital acquired
Long-term debt, including amounts due currently
Commodity and other derivative contractual liabilities
Accumulated deferred income taxes
Other noncurrent liabilities and deferred credits
Total liabilities assumed
Identifiable net assets acquired
Ambit
Transaction
Crius
Transaction
49
29
263
214
23
13
591
—
28
—
8
36
555
$
$
26
(4)
292
257
18
18
607
141
40
9
17
207
400
$
$
In the year ended December 31, 2019, acquisition costs incurred in the Ambit and Crius Transactions 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 and Crius Transactions include intangible amortization and transition related expenses.
97
Ambit and Crius Transaction Unaudited Pro Forma Financial Information — The following unaudited consolidated pro
forma financial information for the years ended December 31, 2019 and 2018 assumes that the Ambit and Crius Transactions
occurred on January 1, 2018 (i.e., represents our results for the years ended December 31, 2019 and 2018 plus the results for
either Ambit or Crius for the period not owned by us, respectively). The unaudited consolidated pro forma financial
information is provided for informational purposes only and is not necessarily indicative of the results of operations that would
have occurred had the Ambit and Crius Transactions been completed on January 1, 2018, nor is the unaudited consolidated pro
forma financial information indicative of future results of operations, which may differ materially from the consolidated pro
forma financial information presented here.
Revenues
Net income (loss) (a)
Net income (loss) attributable to Vistra Energy
Net income (loss) attributable to Vistra Energy per
weighted average share of common stock outstanding —
basic
Net income (loss) attributable to Vistra Energy per
weighted average share of common stock outstanding —
diluted
$
$
$
$
$
Ambit Transaction
Crius Transaction
Year Ended December 31,
Year Ended December 31,
2019
2018
2019
2018
12,931
949
951
$
$
$
10,446
$
(95) $
(93) $
12,373
876
878
$
$
$
10,379
(43)
(41)
1.92
$
(0.18) $
1.78
$
(0.08)
1.90
$
(0.18) $
1.76
$
(0.08)
__________
(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 information 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.
Dynegy Merger Transaction
On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement.
Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the
surviving corporation. The Merger was intended to qualify as a tax-free reorganization under the Internal Revenue Code, as
amended, so that none of Vistra Energy, Dynegy or any of the Dynegy stockholders would recognize any gain or loss in the
transaction, except that Dynegy stockholders could recognize a gain or loss with respect to cash received in lieu of fractional
shares of Vistra Energy's common stock. Vistra Energy is the acquirer for both federal tax and accounting purposes.
At the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share,
other than shares owned by Vistra Energy or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, was
automatically converted into 0.652 shares of common stock, par value $0.01 per share, of Vistra Energy (the Exchange Ratio),
except that cash was paid in lieu of fractional shares, which resulted in Vistra Energy issuing 94,409,573 shares of Vistra
Energy common stock to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible
equity units and warrants. The total number of Vistra Energy shares outstanding at the close of the Merger was 522,932,453
shares. Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally
automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect
to Vistra Energy's common stock, after giving effect to the Exchange Ratio.
Dynegy Business Combination Accounting
We believe the Merger has provided and continues to provide significant strategic benefits and opportunities to Vistra
Energy, including increased scale and market diversification, rebalanced asset portfolio and improved earnings and cash flow.
The Merger was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets
acquired and liabilities assumed recorded at their estimated fair values on the Merger Date. The combined results of operations
are reported in our consolidated financial statements beginning as of the Merger Date. A summary of the techniques used to
estimate the 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 capital was valued using available market information (Level 2).
98
•
•
•
•
•
Acquired property, plant and equipment was valued using a combination of an income approach and a market
approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model
(Level 3).
Acquired derivatives were valued using the methods described in Note 15 (Level 1, Level 2 or Level 3).
Contracts with terms that were not at current market prices were also valued using a discounted cash flow analysis
(Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market
prices with the resulting difference discounted to present value and recorded as either an intangible asset or liability.
Long-term debt was valued using a market approach (Level 2).
AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).
The following table summarizes the consideration paid and the final allocation of the purchase price to the fair value
amounts recognized for the assets acquired and liabilities assumed related to the Merger as of the Merger Date. Based on the
opening price of Vistra Energy common stock on the Merger Date, the purchase price was approximately $2.3 billion. During
the three months ended March 31, 2019, the purchase price allocation was completed. During the period from April 9, 2018
through March 31, 2019, we updated the initial purchase price allocation with final valuations by increasing property, plant and
equipment by $173 million, decreasing intangible assets by $36 million, increasing goodwill by $175 million, decreasing
accounts receivable, inventory, prepaid expenses and other current assets by $10 million, increasing accumulated deferred tax
asset by $127 million, decreasing other noncurrent assets by $113 million, increasing trade accounts payable and other current
liabilities by $89 million, increasing other noncurrent liabilities by $177 million, increasing asset retirement obligations,
including amounts due currently by $56 million as well as other minor adjustments. The valuation revisions were a result of
updated inputs used in determining the fair value of the acquired assets and liabilities.
Dynegy shares outstanding as of April 9, 2018 (in millions)
Exchange Ratio
Vistra Energy shares issued for Dynegy shares outstanding (in millions)
Opening price of Vistra Energy common stock on April 9, 2018
Purchase price for common stock
Fair value of equity component of tangible equity units
Fair value of outstanding stock compensation awards attributable to pre-combination service
Fair value of outstanding warrants
Total purchase price
Dynegy Merger Final Purchase Price Allocation
Cash and cash equivalents
Trade accounts receivables, inventories, prepaid expenses and other current assets
Property, plant and equipment
Accumulated deferred income taxes
Identifiable intangible assets
Goodwill
Other noncurrent assets
Total assets acquired
Trade accounts payable and other current liabilities
Commodity and other derivative contractual assets and liabilities, net
Asset retirement obligations, including amounts due currently
Long-term debt, including amounts due currently
Other noncurrent liabilities
Total liabilities assumed
Identifiable net assets acquired
Noncontrolling interest in subsidiary
Total purchase price
99
144.8
0.652
94.4
19.87
1,876
369
26
2
2,273
445
853
10,535
518
351
175
419
13,296
733
422
475
8,919
469
11,018
2,278
5
2,273
$
$
$
$
$
Acquisition costs incurred in the Merger totaled less than $1 million and $25 million for the years ended December 31,
2019 and 2018, respectively. For the period from the Merger Date through December 31, 2018, our consolidated statements of
operations include revenues and net income (loss) acquired in the Merger totaling $3.902 billion and $224 million respectively.
Dynegy Merger Unaudited Pro Forma Financial Information — The following unaudited pro forma financial
information for the year ended December 31, 2018 and 2017 assumes that the Merger occurred on January 1, 2017. The
unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the
results of operations that would have occurred had the Merger been completed on January 1, 2017, nor is the unaudited pro
forma financial information indicative of future results of operations, which may differ materially from the pro forma financial
information presented here.
Revenues
Net loss
Net loss attributable to Vistra Energy
Net loss attributable to Vistra Energy per weighted average share of common stock
outstanding — basic
Net loss attributable to Vistra Energy per weighted average share of common stock
outstanding — diluted
Year Ended December 31,
2018
2017
10,595
$
(268) $
(265) $
10,509
(969)
(983)
(0.52) $
(1.83)
(0.52) $
(1.83)
$
$
$
$
$
The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and
amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the
Merger, effects of the Merger on tax expense (benefit), changes in the expected impacts of the tax receivable agreement due to
the Merger, and other related adjustments.
100
3.
ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES
Battery Energy Storage Projects
Upton 2 — We have completed the construction of our first battery energy storage system (ESS). In October 2018, we
were awarded a $1 million grant from the TCEQ for our battery ESS at our Upton 2 solar facility. The grant is part of the
Texas Emissions Reduction Plan. The 10 MW lithium-ion ESS captures excess solar energy produced during the day and
releases the energy in late afternoon and early evening, when demand is highest. The Upton 2 battery ESS became operational
in December 2018.
Oakland — In June 2019, East Bay Community Energy signed a ten-year contract to receive resource adequacy capacity
from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California. The contract is pending
a concurrent utility Market Capability Agreement contract for review and signature. The utility Market Capability Agreement
will then be sent to the California Public Utilities Commission (CPUC) for approval.
Moss Landing — In June 2018, we announced that, subject to approval by the CPUC, we would enter into a 20-year
resource adequacy contract with Pacific Gas and Electric Company (PG&E) to develop a 300 MW battery ESS at our Moss
Landing Power Plant site in California. PG&E filed its application with the CPUC in June 2018 and the CPUC approved the
resource adequacy contract in November 2018. At December 31, 2019, we had accumulated approximately $64 million in
construction work-in-process for this ESS. Under the contract, PG&E will pay us a fixed monthly resource adequacy payment,
while we will receive the energy revenues and incur the costs from dispatching and charging the ESS. We anticipate the Moss
Landing battery ESS will commence commercial operations in the fourth quarter of 2020. PG&E filed for Chapter 11
bankruptcy protection in January 2019. On October 15, 2019, PG&E filed a motion in its bankruptcy proceeding requesting
approval of the assumption of the resource adequacy contract. In early November, the bankruptcy court approved the
assumption motion subject to the CPUC approving the terms of the amendment. The CPUC approved the terms of the
amendment on January 22, 2020 so the resource adequacy contract as amended is now assumed and fully enforceable against
PG&E.
Solar Development Project
Upton 2 — In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power
generation facility in Upton County, Texas (Upton 2). As part of this project, we entered into a turnkey engineering,
procurement and construction agreement to construct the approximately 180 MW facility. We spent approximately $231
million related to this project primarily for progress payments under the engineering, procurement and construction agreement
and the acquisition of the development rights. The facility began test operations in March 2018 and commercial operations
began in June 2018.
Odessa Acquisition
In August 2017, La Frontera Holdings, LLC (La Frontera), an indirect wholly owned subsidiary of Vistra Energy,
purchased a 1,054 MW CCGT natural gas-fueled generation plant (and other related assets and liabilities) located in Odessa,
Texas (Odessa Facility) from Odessa-Ector Power Partners, L.P., an indirect wholly owned subsidiary of Koch Ag & Energy
Solutions, LLC (Koch) (altogether, the Odessa Acquisition). La Frontera paid an aggregate purchase price of approximately
$355 million, plus a five-year earn-out provision, to acquire the Odessa Facility. The purchase price was funded by cash on
hand.
The Odessa Acquisition was accounted for as an asset acquisition. Substantially all of the approximately $355 million
purchase price was assigned to property, plant and equipment in our consolidated balance sheet. Additionally, the initial fair
value associated with an earn-out provision of approximately $16 million was included as consideration in the overall purchase
price. The earn-out provision requires cash payments to be made to Koch if spark-spreads related to the pricing point of the
Odessa Facility exceed certain thresholds. Subsequent to the acquisition, the earn-out provision has been accounted for as a
derivative in our consolidated financial statements. Partial buybacks of the earn-out provision were settled in February and
May 2018.
101
4.
RETIREMENT OF GENERATION FACILITIES
MISO — 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 court in
November 2019, we will retire the Edwards facility by the end of 2022 (see Note 13).
In August 2019, we announced the
planned retirement of four power plants in Illinois with a total installed nameplate generation capacity of 2,068 MW. We
retired these units due to changes in the Illinois multi-pollutant standard rule that require us to retire approximately 2,000 MW
of generation capacity (see Note 13). In light of the provisions of the Federal Power Act and the FERC regulations thereunder,
the affected subsidiaries of Vistra Energy identified the retired units by analyzing the economics of each of our Illinois plants
and designating the least economic units for retirement. Expected plant retirement expenses of $47 million, driven by
severance costs, were accrued in the year ended December 31, 2019 and are included primarily in operating costs of our Asset
Closure segment. 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. The following table details the units that have been or will be
retired in Illinois totaling 2,653 MW. Operational results for retired plants are included in the Asset Closure segment, which is
engaged in the decommissioning and reclamation of retired plants and mines.
Name
Coffeen
Duck Creek
Havana
Hennepin
Edwards
Total
Location (all in the
state of Illinois)
Fuel Type
Net Generation
Capacity (MW)
Number
of Units
Coffeen, IL
Canton, IL
Havana, IL
Hennepin, IL
Bartonville, IL
Coal
Coal
Coal
Coal
Coal
915
425
434
294
585
2,653
2
1
1
2
2
8
Dates Units Taken Offline
November 1, 2019
December 15, 2019
November 1, 2019
November 1, 2019
By the end of 2022
PJM — In August 2018, we filed a notice of suspension of operation with PJM and other mandatory regulatory
notifications related to the retirement of our 51 MW Northeastern Power Company waste coal facility in McAdoo,
Pennsylvania (Northeastern Facility). We decided to retire the Northeastern Facility due to its uneconomic operations and
financial outlook. Following the receipt of regulatory approvals, the Northeastern Facility was retired in October 2018. The
decision to retire the Northeastern Facility did not result in a material impact to the financial statements, and the operational
results of the Northeastern Facility are included in our Asset Closure segment.
Two of our non-operated, jointly held power plants acquired in the Merger, for which our proportional generation capacity
was 883 MW, were retired in May 2018. These units were retired as previously scheduled. No gain or loss was recorded in
conjunction with the retirement of these units, and the operational results of these facilities are included in our Asset Closure
segment. The following table details the units retired.
Name
Location
Fuel Type
Net Generation
Capacity (MW)
Ownership
Interest
Killen
Stuart
Total
Manchester, Ohio
Aberdeen, Ohio
Coal
Coal
33%
39%
204
679
883
Date Units Taken Offline
May 31, 2018
May 24, 2018
102
ERCOT — In January and February 2018, we retired three power plants in Texas with a total installed nameplate
generation capacity of 4,167 MW. We decided to retire these units because they were projected to be uneconomic based on
then current market conditions and would have faced significant environmental costs associated with operating such units. In
the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the
Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement. Expected retirement
expenses were accrued in the third and fourth quarter of 2017 and, as a result, no retirement expenses were recorded related to
these facilities in the year ended December 31, 2018. The operational results of these facilities are included in our Asset
Closure segment. The following table details the units retired.
Name
Location (all in the
state of Texas)
Monticello
Titus County
Sandow
Milam County
Fuel Type
Lignite/Coal
Lignite
Big Brown
Freestone County
Lignite/Coal
Total
Installed Nameplate
Generation
Capacity (MW)
Number
of Units
1,880
1,137
1,150
4,167
3
2
2
7
Date Units Taken Offline
January 4, 2018
January 11, 2018
February 12, 2018
We recorded a charge of approximately $206 million in 2017 related to the retirements, including employee-related
severance costs, non-cash charges for writing off materials inventory and capitalized improvements and changes to the timing
and amounts of asset retirement obligations for mining and plant-related reclamation at these facilities. The charge, all of which
related to our Asset Closure segment, was recorded to operating costs and impairment of long-lived assets in our consolidated
statements of operations. In addition, we will continue the ongoing reclamation work at the plants' mines.
In October 2017, the Company and Alcoa entered into a contract termination agreement pursuant to which the parties
agreed to an early settlement of a long-standing power and mining agreement. In consideration for the early termination, Alcoa
made a payment to Luminant of approximately $238 million in October 2017. The contract termination and related payment
did not result in a material gain or loss. The contract had been important to the overall economic viability of the Sandow plant.
5.
REVENUE
The following tables disaggregate our revenue by major source:
Retail
ERCOT
PJM
NY/NE
MISO
Asset
Closure
CAISO/
Eliminations Consolidated
Year Ended December 31, 2019
$ 4,983
$ — $ — $ — $ — $ — $
— $
4,983
Revenue from contracts with
customers:
Retail energy charge in ERCOT
Retail energy charge in Northeast/
Midwest
Wholesale generation revenue
from ISO/RTO
Capacity revenue
Revenue from other wholesale
contracts
Total revenue from contracts
with customers
Other revenues:
1,818
—
— 1,629
—
—
—
264
—
579
162
521
6,801
1,893
1,262
—
434
181
181
796
Intangible amortization
Hedging and other revenues (a)
Affiliate sales
Total other revenues
Total revenues
—
(15)
86
(245)
— 2,345
2,100
71
$ 3,993
$ 6,872
—
105
1,075
1,180
$ 2,442
(4)
162
181
339
$ 1,135
$
—
215
24
147
386
(17)
12
277
272
658
$
—
194
11
2
207
—
42
92
134
341
—
193
—
9
1,818
3,244
378
1,124
202
11,547
4
132
(3,970)
(3,834)
(3,632) $
(32)
294
—
262
11,809
$
____________
(a)
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.
103
Retail
ERCOT
PJM
NY/NE
MISO
Asset
Closure
CAISO/
Eliminations Consolidated
Year Ended December 31, 2018
$ 4,426
$ — $ — $ — $ — $ — $
— $
4,426
Revenue from contracts with
customers:
Retail energy charge in ERCOT
Retail energy charge in Northeast/
Midwest
Wholesale generation revenue
from ISO/RTO
Capacity revenue
Revenue from other wholesale
contracts
Total revenue from contracts
with customers
Other revenues:
1,123
—
— 1,151
—
—
—
214
—
792
369
29
5,549
1,365
1,190
Intangible amortization
Hedging and other revenues (a)
Affiliate sales
Total other revenues
Total revenues
(1)
(26)
(362)
74
— 1,632
1,269
48
$ 2,634
$ 5,597
2
(62)
595
535
$ 1,725
$
—
544
240
42
826
(9)
(41)
41
(9)
817
—
254
25
133
412
—
218
34
—
252
—
167
30
6
203
(9)
(120)
116
(13)
399
$
—
(106)
225
119
371
$
$
—
7
(2,609)
(2,602)
(2,399) $
1,123
3,126
698
424
9,797
(43)
(610)
—
(653)
9,144
____________
(a)
Includes $380 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 20 for
unrealized net gains (losses) by segment.
Retail Energy Charges
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes
delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 45 days from invoice date.
Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a
series of distinct services and are accounted for as a single performance obligation.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues
are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators
or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these
contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and
variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any
unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and
customer activity and therefore it is not practicable to estimate such amounts.
Wholesale Generation Revenue from ISOs/RTOs
Revenue is recognized when volumes are delivered to the ISO or RTO. Revenue is recognized over time using the output
method based on kilowatt hours delivered and cash is settled within 10 days of invoicing. Vistra Energy operates as a market
participant within ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO and expects to continue to remain under contract with
each ISO or RTO indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted
for as a single performance obligation. When electricity is sold to and purchased from the same ISO or RTO in the same
period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues.
104
Capacity Revenue
We provide capacity to customers through participation in capacity auctions held by the ISO or RTO, or through bilateral
sales. Generation facilities are awarded auction volumes through the ISO or RTO auction and bilateral sales are based on
executed contracts with customers. Capacity revenues consist of revenues billed to a third party at either the market or a
negotiated contract price for making installed generation and demand response capacity available in order to satisfy system
integrity and reliability requirements. Capacity revenues are recognized when the performance obligation is satisfied ratably
over time in accordance with the contracts as our power generation facilities stand ready to deliver power to the customer.
Penalties are assessed by the ISO or RTO against generation facilities if the facility is not available during the capacity period.
The penalties are recorded as a reduction to revenue.
Revenue from Other Wholesale Contracts
Other wholesale contracts include other revenue activity with the ISO or 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 performed. Revenue is recognized over time using the output method based on
kilowatt hours delivered or other applicable measurements, and cash settles shortly after invoicing. Vistra Energy operates as a
market participant within ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO and expects to continue to remain under contract
with each ISO or RTO indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted
for as a single performance obligation.
Other Revenues
Some of our contracts for the sale of electricity meet the definition of a derivative under the accounting standards related
to derivative instruments. Revenue from derivative contracts is not considered revenue from contracts with customers under the
accounting standards related to revenue. Our revenue from the sale of electricity under derivative contracts, including the
impact of unrealized gains or losses on those contracts, is reported in the table above as hedging and other revenues. We have
classified all sales to affiliates that are eliminated in consolidation as other revenues in the table above.
Contract and Other Customer Acquisition Costs
We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life
of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition
rates. The deferred acquisition and contract cost balance as of December 31, 2019 and 2018 and January 1, 2018 was $53
million, $38 million and $22 million, respectively. The amortization related to these costs during the year ended December 31,
2019 and 2018 totaled $21 million and $10 million, respectively, recorded as SG&A expenses, and $9 million and $7 million,
respectively, recorded as a reduction to operating revenues in the consolidated statements of operations.
Practical Expedients
The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize
revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the
volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient.
We 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 Obligations
As of December 31, 2019, we have future performance obligations that are unsatisfied, or partially unsatisfied, relating to
capacity auction volumes awarded through capacity auctions held by the ISO or RTO or through bilateral sales. Therefore, an
obligation exists as of the date of the results of the respective ISO or RTO capacity auction or the contract execution date for
bilateral customers. The transaction price is also set by the results of the capacity auction and/or executed contract. These
obligations total $784 million, $732 million, $426 million, $96 million and $29 million that will be recognized in the years
ending December 31, 2020, 2021, 2022, 2023 and 2024, respectively, and $47 million thereafter. Capacity revenues are
recognized as capacity is made available to the related ISOs or RTOs or bilateral counterparties.
105
Accounts Receivable
The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both
contracts with customers and other activities:
December 31,
2019
2018
Trade accounts receivable from contracts with customers — net
Other trade accounts receivable — net
Total trade accounts receivable — net
____________
(a) At December 31, 2019, includes $175 million of trade accounts receivable related to operations acquired in the Ambit and
951
136
1,087
1,246
119
1,365
$
$
$
$
Crius Transactions.
6. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
The following table provides information regarding our goodwill balance. There have been no impairments of goodwill
since Emergence.
Balance at December 31, 2016 and 2017 (a)
Goodwill recorded in connection with the Merger (b)
Balance at December 31, 2018
Goodwill recorded in connection with the Merger (b)
Goodwill recorded in connection with the Crius Transaction (c)
Goodwill recorded in connection with the Ambit Transaction (c)
Balance at December 31, 2019
$
$
1,907
161
2,068
14
257
214
2,553
_______________
(a) Goodwill totaling $1.907 billion arose in connection with our application of fresh start reporting at Emergence and was
allocated entirely to our ERCOT Retail reporting unit. Of the goodwill recorded at Emergence, $1.686 billion is
deductible for tax purposes over 15 years on a straight-line basis.
(b) Goodwill totaling $175 million arose in connection with the Merger, of which $122 million is recorded in our ERCOT
Generation reporting unit and $53 million is recorded in our ERCOT Retail reporting unit (see Note 2).
(c) Preliminary goodwill arising in connection with the Ambit and Crius Transactions is unassigned to a reporting unit
pending completion of the purchase price allocations. None of the goodwill related to the Crius Transaction is deductible
for tax purposes. The goodwill related to the Ambit Transaction of $214 million is deductible for tax purposes over 15
years on a straight-line basis.
Goodwill and intangible assets with indefinite useful lives are required to be evaluated for impairment at least annually or
whenever events or changes in circumstances indicate an impairment may exist. As of the Effective Date, we have selected
October 1 as our annual goodwill test date. On the most recent goodwill testing date, we applied qualitative factors and
determined that it was more likely than not that the fair value of our ERCOT Generation and ERCOT Retail reporting units
exceeded their carrying value at October 1, 2019. Significant qualitative factors evaluated included reporting unit financial
performance and market multiples, cost factors, customer attrition, and changes in reporting unit book value.
106
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
December 31, 2019
December 31, 2018
Identifiable Intangible Asset
Retail customer relationship
Software and other technology-related assets
Retail and wholesale contracts
Contractual service agreements (a)
Other identifiable intangible assets (b)
Total identifiable intangible assets subject
to amortization
Retail trade names (not subject to amortization)
Mineral interests (not currently subject to
amortization)
Total identifiable intangible assets
$
Gross
Carrying
Amount
2,078
341
315
59
40
Accumulated
Amortization
1,151
$
125
182
5
15
$
2,833
$
1,478
Net
927
216
133
54
25
1,355
1,391
2
2,748
$
$
$
Gross
Carrying
Amount
1,680
270
316
70
42
Accumulated
Amortization
876
$
105
138
—
15
$
2,378
$
1,134
Net
$
804
165
178
70
27
1,244
1,245
4
2,493
$
____________
(a) At December 31, 2019, 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 renewable energy
certificates).
Identifiable intangible liabilities are comprised of the following:
Identifiable Intangible Liability
Contractual service agreements
Purchase and sale of power and capacity
Fuel and transportation purchase contracts
Environmental allowances
Total identifiable intangible liabilities
Year Ended December 31,
2019
2018
110
100
76
—
286
$
$
136
114
81
70
401
$
$
107
Expense related to finite-lived identifiable 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/purchase
and sale/fuel and
transportation
contracts
Other identifiable
intangible assets
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 assets expense (a)
Remaining useful
lives of identifiable
intangible assets at
December 31,
2019 (weighted
average in years)
4
4
4
4
Year Ended December 31,
2019
2018
2017
$
275
$
304
$
420
61
23
148
507
$
$
62
43
58
467
$
38
59
15
532
____________
(a) Amounts recorded in depreciation and amortization totaled $340 million, $370 million and $463 million for the years
ended December 31, 2019, 2018 and 2017 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 credit obligations are accrued 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. The purchase price allocation for the Crius Transaction and
the Ambit Transaction are dependent upon final valuation determinations, which may materially change from our current
estimates. We currently expect the final purchase price allocation will be completed no later than the second quarter of 2020
for the Crius Transaction and the third quarter of 2020 for the Ambit Transaction.
•
•
Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-
contracted retail customer base, including residential and business customers, and is being amortized using an
accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic
benefits are realized over their estimated useful life.
Retail trade names — Our retail trade name intangible asset represents the fair value of the TXU EnergyTM, 4Change
EnergyTM, Homefield, Dynegy Energy Services, TriEagle Energy, U.S. Gas & Electric, Public Power and Ambit
Energy trade names, and was determined to be an indefinite-lived asset not subject to amortization. This intangible
asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and
other indefinite-lived intangible assets. Significant assumptions included within the development of the fair value
estimate include estimated gross margins for future periods and implied royalty rates. On the most recent testing
date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset
exceeded its carrying value at October 1, 2019.
108
•
•
Retail and wholesale contracts/purchase and sale contracts — These intangible assets represent the value of various
retail and wholesale contracts and purchase and sale contracts. The contracts were identified as either assets or
liabilities based on the respective fair values as of the Effective Date, 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.
Contractual service agreements — Our acquired contractual service agreements represent the estimated fair value of
favorable or unfavorable contract obligations with respect
to long-term plant maintenance agreements, rail
transportation agreements and rail car leases, and are being amortized based on the expected usage of the service
agreements over the contract terms. The majority of the plant maintenance services relate to capital improvements
and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment.
Amortization of rail transportation and rail car lease agreements is recorded to fuel, purchased power costs and
delivery fees.
Estimated Amortization of Identifiable Intangible Assets and Liabilities — As of December 31, 2019, the estimated
aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown
below.
Year
2020
2021
2022
2023
2024
7.
INCOME TAXES
Estimated Amortization Expense
356
$
255
$
165
$
119
$
81
$
Vistra Energy files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra
Energy is the corporate parent of the Vistra Energy consolidated group. Pursuant to applicable 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.
Income Tax Expense (Benefit)
The components of our income tax expense (benefit) are as follows:
Current:
U.S. Federal
State
Total current
Deferred:
U.S. Federal
State
Total deferred
Total
Year Ended December 31,
2019
2018
2017
$
$
(1) $
10
9
260
21
281
290
$
(13) $
30
17
(8)
(54)
(62)
(45) $
72
14
86
417
1
418
504
109
Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded:
Income (loss) before income taxes
US federal statutory rate
Income taxes at the U.S. federal statutory rate
Nondeductible TRA accretion
State tax, net of federal benefit
Impacts of tax reform legislation on deferred taxes
Federal and State return to provision adjustment
Remeasurement of historical Vistra Energy deferred taxes for expanded
state footprint
Effect of refundable minimum tax credits no longer subject to
sequestration
Nondeductible compensation
Nondeductible transaction costs
Equity awards
Valuation allowance on state NOLs
Lignite depletion
Texas gross margin amended return
Other
Income tax expense (benefit)
Effective tax rate
Deferred Income Tax Balances
Year Ended December 31,
2019
2018
2017
$
$
1,216
21 %
255
5
48
—
(17)
—
—
3
2
(4)
13
(6)
(3)
(6)
290
23.8 %
(101) $
21 %
(20)
8
22
—
(12)
(54)
(15)
8
3
(3)
20
—
—
(2)
(45) $
44.6 %
250
35 %
88
(80)
13
451
19
—
—
—
—
—
—
—
—
13
504
201.6 %
$
$
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2019 and 2018 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 swaps
Other
Total deferred tax assets
Noncurrent Deferred Income Tax Liabilities
Property, plant and equipment
Total deferred tax liabilities
Valuation allowance
Net Deferred Income Tax Asset
December 31,
2019
2018
73
921
214
257
112
108
43
1,728
554
554
110
1,064
$
$
$
76
958
184
188
109
212
40
1,767
406
406
35
1,326
$
$
$
110
At December 31, 2019, we had total deferred tax assets of approximately $1.064 billion that were substantially comprised
of book and tax basis differences related to our generation and mining property, plant and equipment, as well as federal and
state net operating loss (NOL) carryforwards. Our deferred tax assets were significantly impacted by the Merger. As of
December 31, 2019, we assessed the need for a valuation allowance related to our deferred tax asset and considered both
positive and negative evidence related to the likelihood of realization of the deferred tax assets. In connection with our analysis,
we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income,
and thus no valuation allowance was required. We recognized a partial valuation allowance of $13 million on the net operating
loss carryforwards related to Illinois due to forecasted expiration. In addition, we recognized additional state NOLs that have a
valuation allowance of $58 million through the Dynegy acquisition and $4 million through the Crius acquisition, which has no
impact on our effective tax rate.
At December 31, 2019, we had $3.2 billion pre-tax net operating loss (NOL) carryforwards for federal income tax
purposes that will begin to expire in 2032. At December 31, 2019, we had $164 million alternative minimum tax (AMT)
credits refundable through the TCJA available.
The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax
asset of $3 million and $2 million at December 31, 2019 and 2018, respectively.
Liability for Uncertain Tax Positions
Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed
and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to
the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.
We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were
immaterial for the years ended December 31, 2019, 2018 and 2017. The following table summarizes the changes to the
uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance
sheets for the years ended December 31, 2019 and 2018. We did not have uncertain tax positions or uncertain tax position
activity in the year ended December 31, 2017.
Balance at beginning of period, excluding interest and penalties
Additions allocated in the Merger
Additions based on tax positions related to prior years
Reductions based on tax positions related to prior years
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,
2019
2018
$
$
$
39
—
3
—
87
(3)
126
$
—
39
—
—
—
—
39
Vistra Energy and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and are expected to be
subject to examinations by the IRS and other taxing authorities. Vistra Energy is not currently under audit by the IRS for any
period, although review of Dynegy tax year 2018 continues to progress through the IRS's Compliance Assurance Process audit
program. Crius is currently under audit by the IRS for the tax years 2015, 2016 and 2017. Uncertain tax positions totaling
$126 million at December 31, 2019 reflect the addition of a $87 million reserve related to the deductibility of certain interest on
Vistra Energy's 2018 federal and state tax returns under IRC Section 163(j). Vistra Energy's tax return positions reflect the
approach likely taken in revised U.S. Department of the Treasury guidance expected to be forthcoming in the first half of 2020.
We recorded a reserve for financial reporting purposes to reflect the U.S. Department of the Treasury's original proposed
regulations under Section 163(j). Vistra Energy will reevaluate this reserve at the time new guidance is issued, which is
currently expected in the first quarter of 2020. Uncertain tax positions totaling $39 million at December 31, 2018 arose in
connection with the Merger and our assessment of the assumed liabilities is not complete as discussed in Note 2. We had no
uncertain tax positions at December 31, 2017.
111
Tax Matters Agreement
On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to
take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to
indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.
Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off
between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra Energy is generally required to reimburse EFH Corp.
with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us
with respect to any taxes paid by us that are attributable to EFH Corp.
We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing
authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of
EFH Corp.'s net operating loss deductions.
Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be
expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we
obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off.
Certain of these restrictions apply for two years after the Spin-Off.
Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from
EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we
obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d)
we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp.
that the action will not affect the intended tax treatment of the Spin-Off.
8.
TAX RECEIVABLE AGREEMENT OBLIGATION
On the Effective Date, Vistra Energy entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of
certain former first-lien creditors of TCEH. The TRA generally provides for the payment by us to holders of TRA Rights of
85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a
result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our
assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition
of two CCGT natural gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be
paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.
Pursuant to the TRA, we issued the TRA Rights for the benefit of the first lien secured creditors of TCEH entitled to
receive such TRA Rights under the Plan of Reorganization. Such TRA Rights are entitled to certain registration rights more
fully described in the Registration Rights Agreement (see Note 19).
During the year ended December 31, 2019, we recorded a decrease to the carrying value of the TRA obligation totaling
approximately $22 million as a result of adjustments to the timing of forecasted taxable income and state apportionment due to
the expansion of Vistra Energy's state income tax profile, including Dynegy, Crius and Ambit acquisitions. During the year
ended December 31, 2018, we recorded an increase to the carrying value of the TRA obligation totaling approximately $14
million as a result of changes in the timing of estimated payments and new multistate tax impacts resulting from the Merger.
During the year ended December 31, 2017, we recorded a decrease to the carrying value of the TRA obligation totaling $295
million related to changes in the timing of estimated payments resulting from changes in certain tax assumptions including (a)
the impacts of Luminant's plan to retire its Monticello, Sandow 4, Sandow 5 and Big Brown generation plants and the impacts
of the Alcoa settlement (see Note 4), (b) investment tax credits we expect to receive related to the Upton 2 solar development
project (see Note 3), (c) assets acquired in the Odessa Acquisition (see Note 3) and (d) the impacts of other forecasted tax
amounts.
112
The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax
Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2019, 2018 and 2017.
TRA obligation at the beginning of the period
$
420
$
357
$
Year Ended December 31,
2019
2018
2017
Accretion expense
Changes in tax assumptions impacting timing of payments
Revaluation due to tax reform legislation
Impacts of Tax Receivable Agreement
Payments
TRA obligation at the end of the period
Less amounts due currently
59
(22)
—
37
(2)
455
—
65
14
—
79
(16)
420
—
Noncurrent TRA obligation at the end of the period
$
455
$
420
$
596
82
(62)
(233)
(213)
(26)
357
(24)
333
As of December 31, 2019, the estimated carrying value of the TRA obligation totaled $455 million, which represents the
discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including
but not limited to (a) the federal corporate income tax rate of 21% for 2019 and 2018 and 35% for 2017, (b) estimates of our
taxable income in the current and future years and (c) additional states that Vistra Energy now operates in, including the
relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax
code, various relevant state tax laws and reflects our current estimates of future results of the business. These assumptions are
subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of
December 31, 2019, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be
approximately $1.4 billion, with more than half of such amount expected to be attributable to the first 15 tax years following
Emergence, and the final payment expected to be made approximately 40 years following Emergence (if the TRA is not
terminated earlier pursuant to its terms).
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective
interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA
payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the
obligation.
9.
EARNINGS PER SHARE
Basic earnings per share available 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.
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,
2019
2018
2017
928
$
(54) $
(254)
494,146,268
504,954,371
427,761,460
1.88
$
(0.11) $
5,789,223
—
(0.59)
—
499,935,490
504,954,371
427,761,460
1.86
$
(0.11) $
(0.59)
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the
effect would have been antidilutive totaled 2,447,850, 14,165,813 and 3,642,844 shares for the years ended December 31, 2019,
2018 and 2017, respectively.
113
10. ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM
TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra Energy, has an accounts receivable
financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks
(Purchasers). The Receivables Facility was renewed in July 2019, extending its scheduled termination from August 2019 to
July 2020, with the ability to borrow up to $600 million up to the settlement date in November 2019, after which the amount
available for RecCo reverted to $450 million. The agreement was subsequently amended to allow for a one-time, $560 million
borrowing in November 2019 to take advantage of a seasonally-high receivable balance. The borrowing limit returned to $450
million thereafter.
Under the Receivables Facility, TXU Energy and Dynegy Energy Services are obligated to sell or contribute, on an
their accounts receivable to TXU Energy's special purpose subsidiary, RecCo, a
ongoing basis and without recourse,
consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain
conditions, and may, from time to time, sell an undivided interest in all the receivables acquired from TXU Energy and Dynegy
Energy Services to the Purchasers, and its assets and credit are not available to satisfy the debts and obligations of any person,
including affiliates of RecCo. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the
consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from
financing activities in our consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra
Energy's balance sheet and Vistra Energy reflects a liability equal to the amount advanced by the Purchasers. The Company
records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the trade receivables
on behalf of RecCo and the Purchasers, as applicable.
As of December 31, 2019, outstanding borrowings under the receivables facility totaled $450 million and were supported
by $629 million of RecCo gross receivables. As of December 31, 2018, outstanding borrowings under the receivables facility
totaled $339 million.
114
1,500
800
800
3,100
1,000
1,300
1,300
3,600
—
500
—
—
81
166
747
—
—
—
—
1,000
—
—
1,000
1,707
500
1,147
25
81
166
3,626
24
236
120
70
21
—
471
155
11,065
(191)
10,874
11. LONG-TERM DEBT
Amounts in the table below represent the categories of long-term debt obligations incurred by the Company.
December 31,
2019
2018
$
2,700
$
5,813
Vistra Operations Credit Facilities
Vistra Operations Senior Secured Notes:
3.550% Senior Secured Notes, due July 15, 2024
3.700% Senior Secured Notes, due January 30, 2027
4.300% Senior Secured Notes, due 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
Total Vistra Operations Senior Unsecured Notes
Vistra Energy Senior Unsecured Notes:
7.375% Senior Unsecured Notes, due November 1, 2022
5.875% Senior Unsecured Notes, due June 1, 2023
7.625% Senior Unsecured Notes, due November 1, 2024
8.034% Senior Unsecured Notes, due February 2, 2024
8.000% Senior Unsecured Notes, due January 15, 2025 (a)
8.125% Senior Unsecured Notes, due January 30, 2026
Total Vistra Energy Senior Unsecured Notes
Other:
7.000% Amortizing Notes, due July 1, 2019
Forward Capacity Agreements
Equipment Financing Agreements
Mandatorily redeemable subsidiary preferred stock (b)
8.82% Building Financing due semiannually through February 11, 2022 (c)
Other
Total other long-term debt
Unamortized debt premiums, discounts and issuance costs (d)
Total long-term debt including amounts due currently
Less amounts due currently
Total long-term debt less amounts due currently
—
161
99
—
15
12
287
(55)
10,379
(277)
10,102
$
$
____________
(a) On January 15, 2020, Vistra Energy redeemed all outstanding 8.000% Senior Notes due 2025 at a redemption price equal
to 104.0% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding the date of
redemption.
(b) Shares of mandatorily redeemable preferred stock in PrefCo. This subsidiary preferred stock is accounted for as a debt
instrument under relevant accounting guidance. On October 3, 2019, PrefCo redeemed all of the issued and outstanding
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.
(c) Obligation related to a corporate office space finance lease. This obligation will be funded by amounts held in an escrow
account that is reflected in other noncurrent assets in our consolidated balance sheets.
Includes impact of recording debt assumed in the Merger at fair value.
(d)
115
Vistra Operations Credit Facilities
At December 31, 2019, the Vistra Operations Credit Facilities consisted of up to $5.425 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 $2.7 billion (Term
Loan B-3 Facility). These amounts reflect the following transactions and amendments completed in 2018 and 2019:
•
•
•
•
•
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
Energy to pay the principal, premium and interest due in connection with the redemption by Vistra Energy 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 Offering described
below to repay $889 million of loans 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 in the year ended December 31, 2019, which were capitalized as a noncurrent asset.
In June 2018,
the Vistra Operations Credit Facilities were amended whereby we incurred $2.050 billion of
borrowings under the new Term Loan B-3 Facility and obtained $1.640 billion of incremental Revolving Credit
Facility commitments. The letter of credit sub-facility was also increased by $1.585 billion. The maturity date of the
Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. As discussed below, the proceeds
from the Term Loan B-3 Facility were used to repay borrowings under the credit agreement that Vistra Energy
assumed from Dynegy in connection with the Merger. Additionally, letter of credit term loans totaling $500 million
(Term Loan C Facility) were repaid using $500 million of cash from collateral accounts used to backstop letters of
credit. Fees and expenses related to the amendment to the Vistra Operations Credit Facilities totaled $42 million in
the year ended December 31, 2018, of which $23 million was recorded as interest expense and other charges on the
consolidated statements of operations, $9 million was capitalized as a reduction in the carrying amount of the debt
and $10 million was capitalized as a noncurrent asset.
The Vistra Operations Credit Facilities and related available capacity at December 31, 2019 are presented below.
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
December 31, 2019
Facility
Limit
Cash
Borrowings
Available
Capacity
$
$
2,725
2,700
5,425
$
$
350
2,700
3,050
$
$
1,426
—
1,426
___________
(a)
Facility to be used for general corporate purposes. Facility includes a $2.35 billion letter of credit sub-facility, of which
$949 million of letters of credit were outstanding at December 31, 2019 and which reduce our available capacity. Cash
borrowings under the Revolving Credit Facility are reported in short-term borrowings in our consolidated balance sheets.
(b) Beginning in 2020, 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.
116
In February 2018, June 2018 and November 2019, certain pricing terms for the Vistra Operations Credit Facilities were
amended. We accounted for these transactions as modifications of debt. At December 31, 2019, cash borrowings under the
Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%, and there were
$350 million outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%.
Amounts borrowed under the Term Loan B-3 Facilities bear interest based on applicable LIBOR rates plus fixed spreads of
1.75%. At December 31, 2019, the weighted average interest rates before taking into consideration interest rate swaps on
outstanding borrowings was 3.54% under the Term Loan B-3 Facilities. The Vistra Operations Credit Facilities also provide
for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit
and availability fees payable with respect to any unused portion of the available Revolving Credit Facility.
Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra
Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra
Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that
may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of the Vistra
Operations Credit Facilities.
The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the
Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forth in the Vistra Operations
Credit Facilities.
The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations
(and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the
agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting
Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets,
pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit
Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of
certain customary conditions precedent set forth therein.
The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default
resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties,
material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other
agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving
Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving
borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the
agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first
lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. As of
December 31, 2019, we were in compliance with this financial covenant. Upon the existence of an event of default, the Vistra
Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due
and payable, either automatically or at the election of specified lenders.
117
Interest Rate Swaps — Vistra Energy employs interest rate swaps to hedge our exposure to variable rate debt. As of
December 31, 2019, Vistra Energy has entered into the following series of interest rate swap transactions.
Swapped to fixed
Swapped to variable
Swapped to fixed (a)
Swapped to variable
Swapped to fixed (b)
Swapped to variable (b)
____________
(a)
Notional Amount
$3,000
$700
$720
$720
$3,000
$700
Expiration Date
July 2023
July 2023
February 2024
February 2024
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%
In June 2018, we completed the novation of $1.959 billion of Vistra Energy (legacy Dynegy) interest rate swaps to Vistra
Operations, of which $398 million expired and $841 million were terminated in June 2019.
(b) These swaps are effective from July 2023 through July 2026.
During the three months ended December 31, 2019, Vistra Energy entered into $2.120 billion of new interest rate swaps,
pursuant to which Vistra Energy will pay a variable rate and receive a fixed rate. The terms of these new swaps were matched
against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-
money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms.
The remaining existing swaps continue to hedge our exposure on $2.3 billion of debt from now through July 2026.
Alternative Letter of Credit Facility
Two alternate letter of credit facilities (each, an Alternative LOC Facility, and collectively, the Alternate LOC Facilities)
with an aggregate facility limit of $500 million became effective in the year ended December 31, 2019. At December 31, 2019,
$500 million of letters of credit were outstanding under the Alternate LOC Facilities. Of the total facility limit, $250 million
matures in December 2020 and $250 million matures in December 2021.
Vistra Operations Senior Secured Notes
In 2019, Vistra Operations issued and sold $3.1 billion aggregate principal amount of senior secured notes (Senior
Secured Notes) in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (Senior Secured
Notes Offerings) consisting of the following:
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 fees and expenses) under the Vistra Operations Credit Facility's 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.
(c) Capitalized as a reduction in the carrying amount of the debt.
118
The Senior Secured Notes are and will be fully and unconditionally guaranteed by certain of Vistra Operations' current
and future subsidiaries that also guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a
first-priority 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 Subsidiaries)
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 from 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.
Vistra Operations Senior Unsecured Notes
In 2018 and 2019, Vistra Operations issued and sold $3.6 billion aggregate principal amount of senior unsecured notes
(Vistra Operations Senior Unsecured Notes) in offerings to eligible purchasers under Rule 144A and Regulation S under the
Securities Act (Senior Unsecured Notes Offerings) consisting of the following:
Maturity
Year
2026
2027
2027
Interest Terms
(Due Semiannually in Arrears)
March 1 and September 1
February 15 and August 15
January 31 and July 31
Senior Unsecured Notes
5.500% Senior Unsecured Notes
5.625% Senior Unsecured Notes
5.000% Senior Unsecured Notes
Total
Net Proceeds
Debt issuance and other fees (d)
August 2018
Senior Unsecured
Notes Offering (a)
1,000
$
—
—
1,000
990
12
$
$
$
February 2019
Senior Unsecured
Notes Offering (b)
$
— $
June 2019
Senior Unsecured
Notes Offering (c)
—
—
1,300
1,300
1,287
13
1,300
—
1,300 $
1,287 $
16 $
$
$
$
___________
(a) The August 2018 Senior Unsecured Notes were sold pursuant to a purchase agreement by and among Vistra Operations,
the Guarantor Subsidiaries and Citigroup Global Markets Inc., as representative of the several initial purchasers. Net
proceeds, together with cash on hand and cash received from the funding of the Receivables Facility (see Note 10), were
used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the 2018
Tender Offers.
(b) The February 2019 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 price and accrued interest (together with fees and
expenses) required in connection with (i) the February 2019 Tender Offer, (ii)
the redemption of approximately $35
million aggregate principal amount of our 7.375% senior unsecured notes due 2022 (7.375% senior notes) and
approximately $25 million aggregate principal amount of our outstanding 8.034% senior unsecured notes due 2024
(8.034% senior notes).
(c) 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 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 due 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.
(d) Capitalized as a reduction in the carrying amount of the debt.
The indentures governing the Vistra Operations Senior Unsecured Notes (collectively, as each may be amended or
supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) provide for the full and unconditional
guarantee by the Guarantor Subsidiaries of the punctual payment of the principal and interest on such notes. The Vistra
Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the
ability of the Issuer and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell
all or substantially all of their assets.
119
Vistra Energy Senior Unsecured Notes
Bond Repurchase Program — In November 2018, our board of directors (the Board) authorized a bond repurchase
program under which up to $200 million principal amount of outstanding Vistra Energy Senior Unsecured Notes could be
repurchased. Through December 31, 2019, $119 million principal amount of Vistra Energy Senior Unsecured Notes had been
repurchased. In July 2019, the Board authorized up to $1.0 billion to repay or repurchase any outstanding debt of the Company
(or its subsidiaries), with its authority superseding the previously authorized bond repurchase program.
January 2020 Redemption — In January 2020, Vistra Energy redeemed the entire $81 million aggregate principal amount
outstanding of 8.000% senior unsecured notes due 2025 (8.000% senior notes) at a redemption price equal to 104.0% of the
aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption.
November 2019 Redemption — In November 2019, Vistra Energy redeemed the entire $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. We recorded an extinguishment gain of $9 million
on the transaction in the year ended December 31, 2019.
June 2019 Tender Offer — In June 2019, Vistra Energy 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 $845 million aggregate principal amount of certain notes
assumed in the Merger, including $173 million of 7.375% senior notes and $672 million of 7.625% senior notes. We recorded
an extinguishment gain of $7 million on the transactions in the year ended December 31, 2019. In July 2019, Vistra Energy
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.
February 2019 Tender Offer and Consent Solicitation — In February 2019, Vistra Energy used the net proceeds from the
February 2019 Senior Unsecured Notes Offering to fund a cash tender offer (the February 2019 Tender Offer) to purchase for
cash $1.193 billion aggregate principal amount of 7.375% senior notes assumed in the Merger.
In connection with the February 2019 Tender Offer, Vistra Energy also commenced solicitation of consents from holders
of the 7.375% senior notes. Vistra Energy received the requisite consents from the holders of the 7.375% senior notes and
amended the indenture governing these senior notes to, among other things, eliminate substantially all of the restrictive
covenants and certain events of default.
August 2018 Tender Offers and Consent Solicitations — In August 2018, Vistra Energy used the net proceeds from the
August 2018 Senior Unsecured Notes Offering, proceeds from the Receivables Facility (see Note 10) and cash on hand to fund
cash tender offers (the 2018 Tender Offers) to purchase for cash $1.542 billion aggregate principal amount of Vistra Energy
Senior Unsecured Notes assumed in the Merger. We recorded an extinguishment loss of $27 million on the transactions in the
year ended December 31, 2018. Notes purchased consisted of the following:
•
•
•
•
$26 million of 7.625% senior notes;
$163 million of 8.034% senior notes;
$669 million of 8.000% senior notes, and
$684 million of 8.125% senior unsecured notes due 2026 (8.125% senior notes).
In connection with the 2018 Tender Offers, Vistra Energy also commenced solicitations of consents from holders of the
7.375% senior notes, the 7.625% senior notes, the 8.034% senior notes, the 8.000% senior notes and the 8.125% senior notes to
amend certain provisions of the applicable indentures governing each series of senior notes and the registration rights agreement
with respect to the 8.125% senior notes. Vistra Energy received the requisite consents from the holders of the 8.034% senior
notes, the 8.000% senior notes and the 8.125% senior notes (collectively, the Consent Senior Notes) and amended (a) the
indentures governing each series of the applicable senior notes to, among other things, eliminate substantially all of the
restrictive covenants and certain events of default and (b) the registration rights agreement with respect to the 8.125% senior
notes to remove, among other things, the requirement that Vistra Energy commence an exchange offer to issue registered
securities in exchange for the existing, nonregistered notes.
120
Assumption of Senior Notes in Merger — On the Merger Date, Vistra Energy assumed $6.138 billion principal amount of
Dynegy's senior unsecured notes.
In May 2018, $850 million of outstanding 6.75% senior unsecured notes due 2019 were
redeemed at a redemption price of 101.7% of the aggregate principal amount, plus accrued and unpaid interest up to but not
including the date of redemption. Fees and expenses related to the redemption totaled $14 million in the year ended December
31, 2018 and were recorded as interest expense and other charges on the consolidated statements of operations. In June 2018,
each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities (and did not already guarantee the
senior notes) provided a guarantee on the senior notes that remained outstanding.
The senior notes that remain outstanding after the closing of the June 2019 Tender Offer, the February 2019 Tender Offer
and the 2018 Tender Offers are unsecured and unsubordinated obligations of Vistra Energy and are guaranteed by substantially
all of its current and future wholly owned domestic subsidiaries that from time to time are a borrower or guarantor under the
agreement governing the Vistra Operations Credit Facilities (Credit Facilities Agreement) (see Note 22). Except with respect to
the Consent Senior Notes, the respective indentures of the senior notes of Vistra Energy (collectively, as each may be amended
or supplemented from time to time, the Vistra Energy Senior Unsecured Indentures) limit, among other things, the ability of the
Company or any of the guarantors to create liens upon any principal property to secure debt for borrowed money in excess of,
among other limitations, 30% of total assets. The Vistra Energy Senior Unsecured Indentures also contain customary events of
default which would permit the holders of the applicable series of senior notes to declare such notes to be immediately due and
payable if not cured within applicable grace periods, including the failure to make timely principal or interest payments on such
notes or (except with respect to the Consent Senior Notes) other indebtedness aggregating $100 million or more, and, except
with respect to the Consent Senior Notes, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.
Other Long-Term Debt
Amortizing Notes — On the Merger Date, Vistra Energy assumed the obligations of Dynegy's senior unsecured amortizing
note (Amortizing Notes) that matured 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
and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the indenture (Amortizing Notes
Indenture). On the maturity date, the Company paid all amounts due under the Amortizing Notes Indenture and the Amortizing
Notes Indenture ceased to be of further force and effect.
Forward Capacity Agreements — On the Merger Date, the Company assumed the obligation of Dynegy's agreements
under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a
financial institution (Forward Capacity Agreements). The buyer in this transaction will receive capacity payments from PJM
during the Planning Years 2019-2020 and 2020-2021 in the amounts of $51 million and $110 million, respectively. We will
continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for
those planning years. As a result, this transaction is accounted for as long-term debt of $161 million with an implied interest
rate of 3.01%.
Equipment Financing Agreements — On the Merger Date, the Company assumed Dynegy's Equipment Financing
Agreements. Under certain of our contractual service agreements in which we receive maintenance and capital improvements
for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and
availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging
from 2019 to 2026. The portion of future payments attributable to principal will be classified as cash outflows from financing
activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities
in our statements of consolidated cash flows.
Mandatorily Redeemable Subsidiary Preferred Stock — 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.
121
Debt Assumed in Crius Transaction — On the Crius Acquisition Date, Vistra Energy assumed $140 million in long-term
debt obligations in connection with the Crius Transaction consisting of the following:
•
•
•
$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 2027, and
$88 million of borrowings and $9 million of issued letters of credit under the legacy Crius credit facility.
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
In November 2019, borrowings of $8 million under the CT DECD term loans were repaid using cash on
promissory notes.
hand.
Debt Assumed in Ambit Transaction — All of the indebtedness outstanding at Ambit immediately prior to the closing of
the Ambit Transaction was repaid at closing out of the purchase price.
At December 31, 2019, approximately $8 million of letters of credit were outstanding under legacy Ambit agreements, all
of which are collateralized with cash and recorded as restricted cash in the consolidated balance sheets.
Vistra Energy (legacy Dynegy) Credit Agreement — On the Merger Date, Vistra Energy assumed the obligations under
Dynegy's $3.563 billion credit agreement consisting of a $2.018 billion senior secured term loan facility due 2024 and a $1.545
billion senior secured revolving credit facility. As of the Merger Date, there were no cash borrowings and $656 million of
letters of credit outstanding under the senior secured revolving credit facility. On April 23, 2018, $70 million of the senior
In June 2018, the $2.018 billion senior secured term loan facility due 2024 was
secured revolving credit facility matured.
repaid using proceeds from the Term Loan B-3 Facility. In addition, all letters of credit outstanding under the senior secured
revolving credit facility were replaced with letters of credit under the amended Vistra Operations Credit Facilities discussed
above, and the revolving credit facility assumed from Dynegy in connection with the Merger was paid off in full and
terminated.
Maturities
Long-term debt maturities at December 31, 2019 are as follows:
2020
2021
2022
2023
2024
Thereafter
Unamortized premiums, discounts and debt issuance costs
Total long-term debt, including amounts due currently
12. LEASES
December 31, 2019
273
$
94
42
538
1,538
7,949
(55)
10,379
$
Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease
terms for 1 to 38 years. Our leases include options to renew up to 15 years. Certain leases also contain options to terminate the
lease.
122
Lease Cost
The following table 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
Variable lease cost (a)
Short-term lease cost
Sublease income (b)
Net lease cost
Year Ended
December 31,
2019
$
$
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.
Balance Sheet Information
The following table 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 liabilities:
Operating lease liabilities
Finance lease liabilities
Total current lease liabilities
Noncurrent lease liabilities:
Operating lease liabilities
Finance lease liabilities
Total noncurrent lease liabilities
Total lease liabilities
December 31,
2019
$
$
44
59
103
14
8
22
41
78
119
141
123
Cash Flow and Other Information
The following table presents lease related cash flow and other information:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
Operating cash flows from finance leases
Finance cash flows from finance 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
Weighted Average Remaining Lease Term
The following table presents weighted average remaining lease term information:
Year Ended
December 31,
2019
$
17
4
4
95
13
(41)
50
Weighted average remaining lease term:
Operating lease
Finance lease
Weighted average discount rate:
Operating lease
Finance lease
Maturity of Lease Liabilities
The following table presents maturity of lease liabilities:
2020
2021
2022
2023
2024
Thereafter
Total lease payments
Less: Interest
Present value of lease liabilities
December 31,
2019
7.5 years
16.2 years
5.34%
5.84%
Total Lease
29
22
20
20
16
82
189
(48)
141
Operating Lease
17
$
11
9
10
6
13
66
(11)
55
$
Finance Lease
12
11
11
10
10
69
123
(37)
86
$
$
$
$
As of December 31, 2019, we have approximately $24 million of operating leases that have not yet commenced.
124
13. COMMITMENTS AND CONTINGENCIES
Contractual Commitments
At December 31, 2019, we had contractual commitments under long-term service and maintenance contracts, energy-
related contracts, leases and other agreements as follows.
Long-Term Service
and Maintenance
Contracts
Coal purchase and
transportation
agreements
Pipeline transportation
and storage reservation
fees
Nuclear
Fuel Contracts
Other
Contracts
2020
2021
2022
2023
2024
Thereafter
Total
$
$
167
153
171
152
161
1,975
2,779
$
$
576
61
47
33
34
112
863
$
$
109
83
55
46
32
138
463
$
$
90
74
54
57
39
140
454
$
$
174
30
16
16
17
51
304
The table above excludes TRA and pension and OPEB plan obligations due to the uncertainty in the timing of those
payments.
Expenditures under our coal purchase and coal transportation agreements totaled $1.092 billion, $955 million, and $416
million for the years ended December 31, 2019, 2018 and 2017, respectively.
Rent reported as operating costs, fuel costs and SG&A expenses totaled $89 million, $74 million, and $69 million for the
years ended December 31, 2019, 2018 and 2017, respectively.
Guarantees
We have entered into contracts, including the assumed Dynegy senior unsecured notes described above, that contain
guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31,
2019, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required
to make any material payments under these guarantees in the near term.
Letters of Credit
At December 31, 2019, we had outstanding letters of credit totaling $1.457 billion as follows:
•
•
•
•
•
$1.150 billion to support commodity risk management collateral requirements in the normal course of business,
including over-the-counter and exchange-traded transactions and collateral postings with ISOs or RTOs;
$155 million to support battery and solar development projects;
$47 million to support executory contracts and insurance agreements;
$38 million to support our REP financial requirements with the PUCT, and
$67 million for other credit support requirements.
Surety Bonds
At December 31, 2019, we had outstanding surety bonds totaling $62 million to support performance under various
contracts and legal obligations in the normal course of business.
125
Litigation and Regulatory Proceedings
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
concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the
probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably 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
estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject
to inherent
uncertainties and unfavorable 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.
Gas Index Pricing Litigation — We, through our subsidiaries, and other energy companies are named as defendants in
several lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to
various index publications, wash trading and churn trading from 2000-2002. The cases allege that the defendants engaged in an
antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state
antitrust statutes. We remain as defendants in two consolidated putative class actions (Wisconsin) and one individual action
(Kansas) both pending in federal court in those states.
Advatech Dispute — In October 2018, Illinois Power Generating Company (Genco) defended an arbitration filed by
Advatech LLC (Advatech) alleging $81 million in termination charges under the Second Amended and Restated Newton Flue
Gas Desulfurization System Engineering, Procurement, Construction and Commissioning Services Contract dated as of
December 15, 2014. An arbitration panel issued a final award in June 2019. In June 2019, Genco moved to vacate the award in
the U.S. District Court for the Southern District of Illinois, and Advatech moved to confirm the award in the U.S. District Court
for the Northern District of Illinois, which was stayed pending a decision by the Southern District of Illinois on the issue of
venue. In December 2019, the parties entered into a confidential settlement to resolve the matter for less than the amount of the
liability that the Company recorded as part of our purchase price allocation of the Merger. In connection with the settlement,
both parties dismissed their lawsuits related to the award with prejudice and Advatech dismissed its related mechanic lien action
and released its mechanics lien on the Newton plant. This matter is fully resolved.
Wood River Rail Dispute — In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that
BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's
suspension of its Wood River Rail Transportation Agreement with the railroads. Settlement discussions required under the
dispute resolution process have been unsuccessful. In March 2018, BNSF Railway Company and Norfolk Southern Railway
Company filed a demand for arbitration and an arbitration hearing is currently scheduled for November 2020.
ME2C Patent Dispute – In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs)
filed a patent infringement complaint in federal court in Delaware against numerous parties, including Vistra Energy and some
of its subsidiaries (collectively, the Vistra defendants). The complaint alleges that the Vistra defendants infringed two patents
owned by the plaintiffs by using specific processes for mercury control at certain coal-fueled plants. The complaint seeks
injunctive relief and unspecified damages.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from electricity generation units,
referred to as the Clean Power Plan, including rules for existing facilities that would establish state-specific emissions rate goals
to reduce nationwide CO2 emissions. Various parties filed petitions for review in the U.S. Court of Appeals for the District of
Columbia Circuit (D.C. Circuit Court). In July 2019, petitioners filed a joint motion to dismiss in light of the EPA's new rule
that replaces the Clean Power Plan, the Affordable Clean Energy rule, discussed below. In September 2019, the D.C. Circuit
Court granted petitioners' motion to dismiss and dismissed all of the petitions challenging the Clean Power Plan as moot.
126
In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with new regulations addressing GHG emissions
from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule
develops emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled
electric generating units. States must submit their plans for regulating GHG emissions from existing facilities by July 2022.
States where we operate coal plants (Texas, Illinois and Ohio) have begun the development of their state plans to comply with
the rule. Environmental groups and certain states filed petitions for review of the ACE rule and the repeal of the Clean Power
Plan in the D.C. Circuit Court. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards
for new, modified and reconstructed units. Vistra Energy submitted comments on that proposed rulemaking.
Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas
In January 2016,
the EPA issued a final rule approving in part and disapproving in part Texas's 2009 State
Implementation Plan (SIP) as it relates to the reasonable progress component of the Regional Haze program and issuing a
Federal Implementation Plan (FIP). The EPA's emission limits in the FIP assume additional control equipment for specific
lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity
generation units (including Big Brown Units 1 and 2, Monticello Units 1 and 2 and Coleto Creek) and upgrades to existing
scrubbers at seven generation units (including Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4).
In March 2016, various parties (including Luminant and the State of Texas) filed petitions for review in the U.S. Court of
In July 2016, the Fifth Circuit
Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the FIP's Texas requirements.
Court granted motions to stay the rule pending final review of the petitions for review. In March 2017, the Fifth Circuit Court
granted a motion by the EPA to remand the rule back to the EPA for reconsideration. The stay of the rule (and the emission
control requirements) remains in effect. The retirements of our Monticello, Big Brown and Sandow 4 plants should have a
favorable impact on this rulemaking and litigation since these plants constitute a large portion of the plants that the rule seeks to
regulate. Further, we believe that these retirements and the BART rule (discussed below) obviates the need for any additional
limits on our remaining Texas plants to address the requirements in the regional haze rule.
In September 2017, the EPA signed a final rule addressing BART for Texas electricity generation units, with the rule
serving as a partial approval of Texas's 2009 SIP and a partial FIP. For SO2, the rule creates an intrastate Texas emission
allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The
program includes 39 generating units (including our Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2
and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. We believe the retirements of
our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO2. For NOX, the
rule adopts the CSAPR's ozone program as BART and for particulate matter, the rule approves Texas's SIP that determines that
no electricity generation units are subject to BART for particulate matter. Various parties filed a petition challenging the rule in
the Fifth Circuit Court as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA
In March 2018, the Fifth Circuit Court abated its proceedings until the EPA concludes the
in the Fifth Circuit Court action.
reconsideration process. In August 2018, the EPA issued a proposal to affirm the prior BART final rule and seeking comments
on that proposal, which were due in October 2018.
In November 2019, the EPA proposed additional revisions to the BART
final rule, and we submitted comments on that proposal in January 2020.
Affirmative Defenses During Malfunctions
In May 2015, the EPA finalized a rule requiring 36 states, including Texas, Illinois and Ohio, to remove or replace either
EPA-approved exemptions or affirmative defense provisions for excess emissions during upset events and unplanned
maintenance and startup and shutdown events, referred to as the SIP Call. Various parties (including Luminant, the State of
Texas and the State of Ohio) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the
D.C. Circuit Court.
In April 2019, the EPA
Region 6 proposed a rule to withdraw the SIP Call with respect to the Texas affirmative defense provisions. We submitted
comments on that proposed rulemaking in June 2019. In January 2020, the EPA took final action to withdraw the Texas SIP
Call.
In April 2017, the D.C. Circuit Court ordered the case to be held in abeyance.
127
Illinois Multi-Pollutant Standards (MPS)
In August 2019, changes proposed by the Illinois Pollution Control Board to the Illinois multi-pollutant standard rule
(MPS rule), which places NOx, SO2 and mercury emissions limits on our coal plants located in MISO went into effect. Under
the revised MPS rule, our allowable SO2 and NOx emissions from the MISO fleet are 48% and 42% lower, respectively, than
prior to the rule changes. The revised MPS rule requires the continuous operation of existing selective catalytic reduction
(SCR) control systems during the ozone season, requires SCR-controlled units to meet an ozone season NOx emission rate
limit, and set an additional, site-specific annual SO2 limit for our Joppa Power Station. Additionally, in 2019, the Company
retired its Havana, Hennepin, Coffeen and Duck Creek plants in order to comply with the MPS rule's requirement to retire at
least 2,000 MW of the company's generation in MISO. See Note 4 for information regarding the retirement of the four plants.
SO2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello
and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas.
In
February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court.
Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the
EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for
reconsideration to the EPA.
In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if
finalized, would revise its previous nonattainment designations and each area at issue would be designated unclassifiable. In
September 2019, we submitted comments in support of the proposed Error Correction Rule.
Effluent Limitation Guidelines (ELGs)
In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent
standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom
ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were
consolidated in the Fifth Circuit Court.
In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule
and administratively stayed the rule's compliance date deadlines. In August 2017, the EPA announced that its reconsideration
of the ELG rule 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 rule for the application of effluent limitations for FGD
and bottom ash wastewaters from November 1, 2018 to November 1, 2020. Based on these administrative developments, the
Fifth Circuit Court agreed to sever and hold in abeyance challenges to 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 rule pertaining to
effluent limitations for legacy wastewater and leachate. In November 2019, the EPA issued a proposal that would extend the
compliance deadline for FGD wastewater to no later than December 31, 2025 and maintains the December 31, 2023 compliance
date for bottom ash transport water. The proposal also creates new sub-categories of facilities with more flexible FGD
compliance options, including a retirement exemption to 2028 and a low utilization boiler exemption. The proposed rule also
modified some of the FGD final effluent limitations. We filed comments on the proposal in January 2020.
Given the EPA's decision to reconsider the FGD and bottom ash wastewater provisions of the ELG rule, the rule
postponing the ELG rule's earliest compliance dates for those provisions, the uncertainty stemming from the vacatur of the
effluent limitations for legacy wastewater and leachate, and the intertwined relationship of the ELG rule with the Coal
Combustion Residuals rule discussed below, which is also being reconsidered by the EPA, as well as pending legal challenges
concerning both rules, substantial uncertainty exists regarding our projected capital expenditures for ELG compliance,
including the timing of such expenditures.
CAA Matters
Zimmer NOVs — In December 2014, the EPA issued a notice of violation (NOV) alleging violation of opacity standards
at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the
Ohio State Implementation Plan and the station's air permits including standards applicable to opacity, sulfur dioxide, sulfuric
acid mist and heat input. In January 2020, the U.S. Department of Justice filed a complaint and proposed consent decree agreed
to by Dynegy Zimmer, LLC in the U.S. District Court for the Southern District of Ohio that would resolve claims alleged in the
2008, 2010 and 2014 NOVs. The court has not yet entered the consent decree as effective. We believe that if the consent
decree is entered by the court as proposed, it will not have a material impact on our results of operations, liquidity or financial
condition.
128
Edwards CAA Citizen Suit — In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for
the Central District of Illinois against one of our subsidiaries that owns the Edwards Power Plant alleging violations of opacity
and particulate matter limits at our MISO segment's Edwards facility. In August 2016, the district court granted the plaintiffs'
motion for summary judgment on certain liability issues. In September 2019, the parties to the lawsuit announced a proposed
settlement which was approved by the court in a consent decree in November 2019. The consent decree requires the retirement
of the Edwards plant by the end of 2022 and funding for certain projects that benefit Peoria-area communities. See Note 4 for
information regarding the retirement of the Edwards plant.
Coal Combustion Residuals (CCR)/Groundwater
In July 2018, the EPA published a final rule, which became effective in August 2018, that amends certain provisions of
the CCR rule that the agency issued in 2015. Among other changes, the 2018 revisions extend closure deadlines to October 31,
2020, related to the aquifer location restriction and groundwater monitoring requirements. Also, in August 2018, the D.C.
Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability
exemption for legacy impoundments. The EPA is expected to undertake further revisions to its CCR regulations in response to
the D.C. Circuit Court's ruling. In October 2018, the rule that extends certain closure deadlines to 2020 was challenged in the
D.C. Circuit Court. In March 2019, the D.C. Circuit Court granted the EPA's request for remand without vacatur. In December
2019, the EPA issued a proposed rule that would revise the closure deadlines for unlined CCR impoundments from October 31,
2020 to August 31, 2020 and establish new procedures for seeking extensions of that revised closure deadline. One of the new
proposed extension procedures would require the generation plant electing this option to notify the EPA by May 2020 that it
will retire by either 2023 or 2028 depending on the size of the impoundment at issue. If the rule is finalized as proposed, we
may decide to avail ourselves of this compliance mechanism for some of our facilities. We filed comments on the proposal in
January 2020.
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 are working towards implementation of those closure plans.
At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the 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 for additional information regarding the closure of these Vermilion surface
impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options.
In May 2018, Prairie Rivers Network 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 judgment was
entered in our favor. Plaintiffs have appealed the judgment to the U.S. Court of Appeals for the Seventh Circuit. That appeal is
now stayed.
In April 2019, PRN also filed a complaint against DMG before the 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. This matter is in the very early stages.
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 and that notice has since been referred to the Illinois Attorney General.
In December 2018, the Sierra Club filed a complaint with the IPCB alleging the disposal and storage of coal ash at the
Coffeen, Edwards, and Joppa generation facilities are causing exceedances of the applicable groundwater standards.
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. We anticipate IEPA's proposed rule will be issued
in March 2020 and expect the rulemaking process should be completed by early 2021. Under the new law, 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 law does not mandate closure by removal at any site.
129
For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are
necessary at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our
financial condition, results of operations, and cash flows. At this time, in part because of the revisions to the CCR rule that the
EPA published in July 2018, the D.C. Circuit Court's vacatur and remand of certain provisions of the EPA's 2015 CCR rule and
the Illinois coal ash rulemaking, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any,
that ultimately may be required. The currently anticipated CCR surface impoundment and landfill closure costs, as contained in
our AROs, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and
protective of the environment for each location.
MISO 2015-2016 Planning Resource Auction
In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 planning resource
auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc.,
the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as
unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure
going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4
constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was
responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding
occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by
the Complainants. We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff
in connection with the PRA and disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at
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.
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.
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 and stated that those issues remained under consideration and would be addressed in a future
order.
In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation
into Dynegy was closed. FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA
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 order remains subject to rehearing at FERC and appeal.
Other Matters
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions
of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or
financial condition.
Labor Contracts
We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by
collective bargaining agreements. The terms of all collective bargaining agreements covering represented personnel engaged in
lignite mining operations, lignite-, coal- and nuclear-fueled generation operations and some of our natural gas-fueled generation
operations expire on various dates between June 2020 and November 2023, 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 collective bargaining agreements to have a material adverse effect on our results of operations, liquidity or financial
condition.
130
Nuclear Insurance
Nuclear insurance includes nuclear liability coverage, property damage, decontamination and accidental premature
decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or
exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the
Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We
are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms
and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability.
Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition.
With regard to liability coverage, the Act provides for financial protection for the public in the event of a significant
nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $13.5 billion
and requires nuclear generation plant operators to provide financial protection for this amount. However, the United States
Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $13.5 billion limit for a
single incident. As required, we insure against a possible nuclear incident at our Comanche Peak facility resulting in public
nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide
retrospective payment plan known as Secondary Financial Protection (SFP).
Under the SFP, in the event of any single nuclear liability loss in excess of $450 million at any nuclear generation facility
in the United States, each operating licensed reactor in the United States is subject to an annual assessment of up to $137.6
million. This approximately $137.6 million maximum assessment is subject to increases for inflation every five years, with the
next expected adjustment scheduled to occur in September 2023. Assessments are currently limited to $20.5 million per
operating licensed reactor per year per incident. As of December 31, 2019, our maximum potential assessment under the
industry retrospective plan would be approximately $275 million per incident but no more than $41 million in any one year for
each incident. The potential assessment is triggered by a nuclear liability loss in excess of $450 million per accident at any
nuclear facility.
The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain
at least $1.06 billion of nuclear decontamination and property damage insurance, and requires that the proceeds thereof be used
to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the
NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain
nuclear decontamination and property damage insurance for our Comanche Peak facility in the amount of $2.25 billion and
non-nuclear related property damage in the amount of $1.5 billion (subject to a $5 million deductible per accident except for
natural hazards which are subject to a $9.5 million deductible per accident), above which we are self-insured.
We also maintain Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from
another source if one or both of the units at our Comanche Peak facility are out of service for more than twelve weeks as a
result of covered direct physical damage. Such coverage provides for weekly payments per unit up to $4.5 million for the first
52 weeks and up to $3.6 million for the remaining 71 weeks. The total maximum coverage is $328 million for non-nuclear
property damage and $490 million for nuclear property damage. The coverage amounts applicable to each unit will be reduced
to 80% if both units are out of service at the same time as a result of the same accident.
131
14. EQUITY
Equity Issuances and Repurchases
Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2019, 2018
and 2017 are reflected in the table below.
Balance at December 31, 2016
Shares issued (a)
Balance at December 31, 2017
Shares issued (a) (b)
Shares retired
Shares repurchased
Balance at December 31, 2018
Shares issued (a) (c)
Shares retired
Shares repurchased
Balance at December 31, 2019
Shares
Issued
Treasury
Shares
Shares
Outstanding
427,580,232
818,570
428,398,802
97,639,105
(6,815)
— 427,580,232
—
818,570
— 428,398,802
—
—
97,639,105
(6,815)
— (32,815,783)
(32,815,783)
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)
(41,043,224)
528,741,335
(27,001,399)
487,698,111
____________
(a) Shares issued includes share awards granted to nonemployee directors.
(b) The year ended December 31, 2018 includes 94,409,573 shares issued in connection with the Merger (see Note 2).
(c) 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.
Share Repurchase Program
In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of
our outstanding common stock may be purchased. Repurchases under this program were completed in October 2018.
In
November 2018, we announced that the Board had authorized an incremental share repurchase program (Program) under which
up to $1.250 billion of our outstanding stock may be purchased, resulting in an aggregate $1.750 billion share repurchase
program. At December 31, 2019, $332 million was available for additional repurchases under the Program. Shares of common
stock repurchased under the program for the years ended December 31, 2019 and 2018 are reflected in the table below.
$500 Million Board Authorization
$1.250 Billion Board Authorization
Year Ended December 31, 2018
Year Ended December 31, 2019
Totals
Total Number
of Shares
Repurchased
21,421,925 $
—
21,421,925 $
Average Price
Paid Share
Amount Paid
for Shares
Repurchased
500
—
500
23.36 $
—
23.36 $
Total Number
of Shares
Repurchased
12,073,091 $
26,322,166
38,395,257 $
Average Price
Paid Share
Amount Paid
for Shares
Repurchased
278
640
918
22.99 $
24.34
23.92 $
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 Act, or by other means in accordance with
federal securities laws. The actual timing, number and value of shares repurchased under the Program or otherwise will be
determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price
of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt
agreements and the Tax Matters Agreement.
Dividends
In November 2018, Vistra Energy announced 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,
Vistra Energy's results of operations, financial condition and liquidity, Delaware law and any contractual limitations.
132
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, the Board declared a quarterly dividend of $0.135 per share that will be paid in March 2020. Vistra
Energy did not declare or pay any dividends during the year ended December 31, 2018.
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, 2019, Vistra Operations can
distribute approximately $6.0 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 $3.9 billion, $4.7 billion and $1.1 billion during the years ended December 31, 2019, 2018 and
2017, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make
any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or
operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31,
2019, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled
approximately $2.1 billion.
Under applicable Delaware General Corporate Law, we are prohibited from paying any distribution to the extent that such
distribution exceeds the value of our "surplus," which is defined as the excess of our net assets above our capital (the aggregate
par value of all outstanding shares of our stock).
Accumulated Other Comprehensive Income
During the years ended December 31, 2019, 2018 and 2017, we recorded changes in the funded status of our pension and
other postretirement employee benefit liability totaling $11 million, $9 million and $(23) million, respectively. During the
years ended December 31, 2019 and 2018, $(3) million and $(3) million was reclassified from accumulated other
comprehensive income and reported in other deductions. During the year ended December 31, 2017, no amounts were
reclassified from accumulated other comprehensive income.
Warrants
At the Merger Date, the Company entered into an agreement whereby holders of each outstanding warrant previously
issued by Dynegy will be entitled to receive, upon exercise, the equity securities to which the holder would have been entitled
to receive of Dynegy common stock converted into shares of Vistra Energy common stock at the Exchange Ratio. As of
December 31, 2019, nine million warrants expiring in 2024 with an exercise price of $35.00 (subject to adjustment from time-
to-time) were outstanding, each of which can be redeemed for 0.652 share of Vistra Energy common stock. The warrants are
recorded as equity in our consolidated balance sheets.
Tangible Equity Units (TEUs)
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 Energy 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 for as debt while the stock purchase contract was included in equity based on the fair value of
the contract at the Merger Date. 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 Energy common stock were issued in connection with the settlement of all outstanding TEUs.
133
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 comparable assets and liabilities for those
items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and
ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation
techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and
procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Energy
Chief Financial Officer.
Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance
risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the
credit risks associated with our credit standing and the credit standing of our counterparties (see Note 16 for additional
information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in
calculating these fair value measurement adjustments.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
•
•
•
Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the
measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative
exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report
the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of
certain margin amounts related to changes in fair value on certain CME transactions that, beginning in January 2017,
are legally characterized as settlement of derivative contracts rather than collateral.
Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are
corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield
curves observable at commonly quoted intervals. We attempt to obtain multiple quotes from brokers that are active in
the markets in which we participate and require at least one quote from two brokers to determine a pricing input as
observable. The number of broker quotes received for certain pricing inputs varies depending on the depth of the
trading market, each individual broker's publication policy, recent trading volume trends and various other factors.
Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent
observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for
the asset or liability at the measurement date. We use the most meaningful information available from the market
combined with internally developed valuation methodologies to develop our best estimate of fair value. Significant
unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing
delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation
models are developed and maintained by employees trained and experienced in market operations and fair value
measurements and validated by the Company's risk management group.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or
liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the
fair value measurement.
134
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet
dates shown below:
December 31, 2019
Level 1
Level 2
Level 3 (a)
Reclassification (b)
Total
Assets:
Commodity contracts
Interest rate swaps
Nuclear decommissioning trust –
equity securities (c)
Nuclear decommissioning trust –
debt securities (c)
Sub-total
Assets measured at net asset value (d):
Nuclear decommissioning trust –
equity securities (c)
Total assets
Liabilities:
Commodity contracts
Interest rate swaps
Total liabilities
Assets:
Commodity contracts
Interest rate swaps
Nuclear decommissioning trust –
equity securities (c)
Nuclear decommissioning trust –
debt securities (c)
Sub-total
Assets measured at net asset value (d):
Nuclear decommissioning trust –
equity securities (c)
Total assets
Liabilities:
Commodity contracts
Interest rate swaps
Total liabilities
$
$
$
$
$
$
$
$
$
1,047
—
564
—
1,611
$
985
—
985
$
$
172
—
—
521
693
439
177
616
December 31, 2018
Level 1
Level 2
456
—
449
—
905
$
$
152
77
—
443
672
$
$
$
$
$
$
239
—
—
—
239
$
$
313
—
313
$
$
11
—
—
—
11
11
—
11
$
$
$
$
1,469
—
564
521
2,554
366
2,920
1,748
177
1,925
Level 3 (a)
Reclassification (b)
Total
153
—
—
—
153
$
$
1
—
—
—
1
1
—
1
$
$
$
$
762
77
449
443
1,731
278
2,009
1,612
34
1,646
557
—
557
$
$
766
34
800
$
$
288
—
288
$
$
____________
(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.
135
Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial
instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal
purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest
to fixed rates. See Note 16 for further discussion regarding derivative instruments.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and
decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities
consistent with investment rules established by the NRC and the PUCT.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant
unobservable inputs used in the valuations at December 31, 2019 and 2018:
Fair Value
December 31, 2019
Assets
$
64
Liabilities
$
(53) $
Total
11
Valuation
Technique
Valuation
Model
Contract Type (a)
Electricity
purchases and
sales
Significant Unobservable Input
Hourly price curve shape (c) $ — to
Range (b)
Illiquid delivery periods for
ERCOT hub power prices
and heat rates (d)
$ 20
MWh
to
MWh
$ 115
$ 120
Options
38
(188)
(150)
Option
Pricing
Model
Gas to power correlation (e)
Power and gas volatility (e)
10 % to
5 % to
100 %
440 %
Financial
transmission
rights
Other (h)
120
(26)
17
(46)
Total $
239
$
(313) $
94
Market
Approach (f)
Illiquid price differences
between settlement points
(g)
$ (10)
$
40
to
MWh
(29)
(74)
Fair Value
Assets
$
22
Liabilities
$
(48) $
December 31, 2018
Total
Valuation
Technique
(26) Valuation
Model
Significant Unobservable Input
Hourly price curve shape (c) $ — to
Range (b)
Illiquid delivery periods for
ERCOT hub power prices
and heat rates (d)
$ 20
MWh
to
MWh
$ 110
$ 120
31
85
(192)
(161)
Option
Pricing
Model
Gas to power correlation (e)
Power volatility (e)
15 % to
5 % to
95 %
435 %
(20)
65
Market
Approach (f)
Illiquid price differences
between settlement points
(g)
$ (10)
$
50
to
MWh
15
153
$
(28)
(288) $
(13)
(135)
Contract Type (a)
Electricity
purchases and
sales
Options
Financial
transmission
rights
Other (h)
Total $
____________
(a) Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, NYISO, ISO-NE and
MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between
settlement points within are referred to as congestion revenue rights in ERCOT and financial transmission rights in PJM,
NYISO, ISO-NE and MISO regions. Options consist of physical electricity options, spread options, swaptions 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.
(c) Primarily based on the historical range of forward average hourly ERCOT North Hub prices.
136
(d) Primarily based on historical forward ERCOT power prices and ERCOT heat rate variability.
(e) Primarily based on the historical forward correlation and volatility within ERCOT.
(f) While we use the market approach, there is insufficient market data to consider the valuation liquid.
(g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h) Other includes contracts for natural gas, coal and emissions.
There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2019,
2018 and 2017. See the table below for discussion of transfers between Level 2 and Level 3 for the years ended December 31,
2019, 2018 and 2017.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the years ended December
31, 2019, 2018 and 2017.
Net asset (liability) balance at beginning of period
Total unrealized valuation gains (losses)
Purchases, issuances and settlements (a):
Purchases
Issuances
Settlements
Transfers into Level 3 (b)
Transfers out of Level 3 (b)
Net liabilities assumed in connection with the Merger
Earn-out provision (c)
Net change (d)
Net liability balance at end of period
Unrealized valuation losses relating to instruments held at end of period
Year Ended December 31,
2019
2018
2017
(135) $
8
176
(81)
(64)
10
12
—
—
61
(74) $
(53) $
(363)
146
(41)
76
4
133
(37)
—
(82)
(135) $
(61) $
(174) $
83
(136)
69
(22)
(106)
4
71
—
(16)
(136)
(53)
(98)
$
$
$
____________
(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and
issuances reflect option premiums paid or received and purchases of Financial Transmission Rights.
(b) Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods
presented are in and out of Level 2. For the years ended December 31, 2019, 2018 and 2017, transfers out of Level 3
primarily consist of power and coal derivatives where forward pricing inputs have become observable.
(c) Represents initial fair value of the earn-out provision agreed to as part of the Odessa Acquisition.
(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
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price
and interest rate risk. See Note 15 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to
changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets and to hedge
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 institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and
energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as
well as realized gains and losses upon settlement of the instruments are reported in our consolidated statements of operations in
operating revenues and fuel, purchased power costs and delivery fees.
137
Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting
floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and
losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are
reported in our consolidated statements of operations in interest expense and related charges.
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent
with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of
derivative contractual assets and liabilities as reported in our consolidated balance sheets at December 31, 2019 and 2018.
Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross
value of the contract.
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Net assets (liabilities)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Net assets (liabilities)
Derivative Assets
Derivative Liabilities
December 31, 2019
Commodity
Contracts
Interest Rate
Swaps
Commodity
Contracts
Interest Rate
Swaps
Total
1,323
136
(1)
—
1,458
$
$
— $
—
—
—
— $
$
10
—
(1,510)
(237)
(1,737) $
— $
—
(18)
(159)
(177) $
1,333
136
(1,529)
(396)
(456)
Derivative Assets
Derivative Liabilities
December 31, 2018
Commodity
Contracts
Interest Rate
Swaps
Commodity
Contracts
Interest Rate
Swaps
Total
707
54
—
—
761
$
$
22
55
—
—
77
$
$
$
1
—
(1,374)
(238)
(1,611) $
— $
—
(2)
(32)
(34) $
730
109
(1,376)
(270)
(807)
$
$
$
$
At December 31, 2019 and 2018, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized
effects. Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts
related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.
Derivative (consolidated statements of operations presentation)
2019
2018
2017
Commodity contracts (Operating revenues)
Commodity contracts (Fuel, purchased power costs and delivery fees)
Interest rate swaps (Interest expense and related charges)
Net gain (loss)
$
$
339
$
(855) $
(1)
(217)
18
(11)
121
$
(848) $
56
6
2
64
Year Ended December 31,
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in our consolidated balance sheets on a gross basis without taking into
consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting
agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce
credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements,
monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract
counterparty.
138
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 capital or other general corporate purposes.
The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into
consideration netting arrangements with counterparties and financial collateral:
December 31, 2019
December 31, 2018
Derivative
Assets
and
Liabilities
Offsetting
Instruments
(a)
Cash
Collateral
(Received)
Pledged (b)
Net
Amounts
Derivative
Assets
and
Liabilities
Offsetting
Instruments
(a)
Cash
Collateral
(Received)
Pledged (b)
Net
Amounts
Derivative assets:
Commodity contracts
Interest rate swaps
Total derivative
assets
Derivative liabilities:
Commodity contracts
Interest rate swaps
Total derivative
liabilities
$
$
1,458
—
(1,113) $
—
— $
—
1,458
(1,113)
(1,737)
(177)
1,113
—
(1,914)
1,113
—
40
—
40
40
345
—
345
(584)
(177)
(761)
$
761
77
838
$
(593) $
(26)
(1) $
—
(619)
(1)
(1,611)
(34)
(1,645)
593
26
619
109
—
109
167
51
218
(909)
(8)
(917)
Net amounts
$
(456) $
— $
$
(416)
$
(807) $
— $
108
$
(699)
____________
(a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin
requirements.
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at December 31, 2019 and 2018:
December 31, 2019
December 31, 2018
Derivative type
Natural gas (a)
Electricity
Financial transmission rights (b)
Coal
Fuel oil
Uranium
Emissions
Renewable energy certificates
Interest rate swaps – floating/fixed (c)
Interest rate swaps - fixed/floating (c)
Notional Volume
6,160
428,367
199,648
22
33
—
20
11
6,720
2,120
$
$
Unit of Measure
7,011 Million MMBtu
317,572 GWh
172,611 GWh
45 Million U.S. tons
60 Million gallons
50 Thousand pounds
10 Million tons
— Million certificates
7,717 Million U.S. dollars
— Million U.S. dollars
$
$
____________
(a) Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas
transactions.
(b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between
(c)
settlement points within ISOs or RTOs.
Includes notional amounts of interest rate swaps with maturity dates through July 2026. See Note 11 for termination of
interest rate swaps.
139
Credit Risk-Related Contingent Features of Derivatives
Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity
requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these
agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include
cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other
financing arrangements related to payment terms or other covenants.
The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are
not fully collateralized:
Fair value of derivative contract liabilities (a)
Offsetting fair value under netting arrangements (b)
Cash collateral and letters of credit
Liquidity exposure
December 31,
2019
2018
$
$
(692) $
167
67
(458) $
(856)
218
190
(448)
____________
(a) Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if
features are triggered, including provisions that generally provide the right to request additional collateral (material
adverse change, performance assurance and other clauses).
(b) Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master
netting arrangements.
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. At December 31, 2019, total
credit risk exposure to all counterparties related to derivative contracts totaled $1.621 billion (including associated accounts
receivable). The net exposure to those counterparties totaled $403 million at December 31, 2019 after taking into effect netting
arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $106 million. At
December 31, 2019, the credit risk exposure to the banking and financial sector represented 74% of the total credit risk
exposure and 40% of the net exposure.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance
because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases
the risk that a default by any of these counterparties would have a material effect on our financial condition, results of
operations and liquidity. The transactions with these counterparties contain certain provisions that would require the
counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize
specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of
positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters
of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment
history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit
with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial
assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement
payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in
receipts of expected settlements if the counterparties owe amounts to us.
140
17. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS
Vistra Energy is the plan sponsor of the Vistra Energy Retirement Plan (the Retirement Plan), which provides benefits to
eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. As Vistra Energy accounts for its interests
in the Retirement Plan as a multiple employer plan, only Vistra Energy's share of the plan assets and obligations are reported in
the pension benefit information presented below. After amendments in 2012, employees in the Retirement Plan now consist
entirely of 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.
Vistra Energy and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of
certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions
required for such coverage vary based on a formula depending on the retiree's age and years of service.
Prior to the Merger, Dynegy provided pension and OPEB benefits to certain of its employees and retirees. At the Merger
Date, Vistra Energy assumed these plans and the excess of the benefit obligations over the fair value of plan assets was
recognized as a liability (see Note 2). Benefit obligations assumed totaled $539 million and the fair value of plan assets
assumed totaled $459 million, and the net unfunded liability was recorded as $15 million to other noncurrent assets, $2 million
to other current liabilities and $93 million to other noncurrent liabilities in the consolidated balance sheets.
Effective January 1, 2018, Vistra Energy entered into a contractual arrangement with Oncor whereby the costs associated
with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the
regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra Energy (or its predecessors) are
split between Oncor and Vistra Energy. Prior to January 1, 2018, coverage for Split Participants was provided by the Oncor
OPEB plan, with Vistra Energy retaining its portion of the liability for coverage for Split Participants.
In addition, Vistra
Energy is the sponsor of an OPEB plan that certain EFH Corp. retirees participate in. As Vistra Energy accounts for its interest
in these OPEB plans as multiple employer plans, only Vistra Energy's share of the plan assets and obligations are reported in
the OPEB information presented below.
Pension and OPEB Costs
Pension costs
OPEB costs
Total benefit costs recognized as expense
Year Ended December 31,
2019
2018
2017
$
$
9
11
20
$
$
14
9
23
$
$
6
6
12
Market-Related Value of Assets Held in Postretirement Benefit Trusts
We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of
calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period.
Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-
related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and
is decreased for benefit payments and expenses for that year.
141
Detailed Information Regarding Pension Benefits
The following information is based on a December 31, 2019, 2018 and 2017 measurement dates:
Assumptions Used to Determine Net Periodic Pension Cost:
Discount rate (Vistra Energy Plan)
Discount rate (Dynegy Plan & EEI Plan)
Expected return on plan assets (Vistra Energy Plan)
Expected return on plan assets (Dynegy Plan)
Expected return on plan assets (EEI Plan)
Expected rate of compensation increase (Vistra Energy Plan)
Expected rate of compensation increase (Dynegy Plan & EEI Plan)
Interest crediting rate for cash balance plans (Vistra Energy Plan)
Interest crediting rate for cash balance plans (Dynegy Plan & EEI Plan)
Components of Net Pension Cost:
Service cost
Interest cost
Expected return on assets
Immediate pension cost
Net periodic pension cost
Other Changes in Plan Assets and Benefit Obligations Recognized in Other
Comprehensive Income:
Net (gain) loss
Total recognized in net periodic benefit cost and other comprehensive
income
Assumptions Used to Determine Benefit Obligations:
Discount rate (Vistra Plan)
Expected rate of compensation increase (Vistra Plan)
Discount rate (Dynegy Plan)
Expected rate of compensation increase (Dynegy Plan)
Interest crediting rate for cash balance plans (Vistra Energy Plan)
Interest crediting rate for cash balance plans (Dynegy Plan & EEI)
$
$
$
$
Year Ended December 31,
2019
2018
2017
4.37 %
4.37 %
4.80 %
5.31 %
5.56 %
3.35 %
3.35 %
3.50 %
3.50 %
7
25
(26)
3
9
11
20
$
$
$
$
3.74 %
4.05 %
4.56 %
5.94 %
4.74 %
3.62 %
3.50 %
3.50 %
4.25 %
15
21
(23)
1
14
14
28
$
$
$
$
3.24 %
3.29 %
3.24 %
3.29 %
3.50 %
3.50 %
4.37 %
3.35 %
4.37 %
3.35 %
3.50 %
3.50 %
4.31 %
— %
4.86 %
— %
— %
3.50 %
— %
4.00 %
— %
5
6
(5)
—
6
3
9
3.74 %
3.62 %
— %
— %
3.50 %
— %
For the year ended December 31, 2019, the net actuarial loss of $16 million was driven by losses attributable to
decreasing discount rates due to changes in the corporate bond markets, actuarial assumption updates to reflect current market
conditions, annuity purchases, plan amendments and plan experience different than expected, partially offset by gains
attributable to actual asset performance exceeding expectations and life expectancy updates.
For the year ended December 31, 2018, the net actuarial loss of $14 million was driven by losses attributable to actual
asset performance falling short of expectations and plan experience different than expected, partially offset by gains attributable
to increasing discount rates due to changes in the corporate bond markets, economic assumption updates to reflect current
market conditions and life expectancy projection updates.
For the year ended December 31, 2017, the net actuarial loss of $3 million was driven by losses attributable to decreasing
discount rates due to changes in the corporate bond markets and demographic assumption updates to reflect current
expectations, partially offset by gains attributable to actual asset performance exceeding expectations, economic assumption
updates to reflect current market conditions, life expectancy projection updates and plan experience different than expected.
142
Change in Pension Obligation:
Projected benefit obligation at beginning of period
Acquisitions
Service cost
Interest cost
Settlement
Curtailment
Annuity purchase
Actuarial (gain) loss
Benefits paid
Projected benefit obligation at end of year
Accumulated benefit obligation at end of year
Change in Plan Assets:
Fair value of assets at beginning of period
Acquisitions
Employer contributions
Settlement
Annuity purchase
Actual gain (loss) on assets
Benefits paid
Fair value of assets at end of year
Funded Status:
Projected pension benefit obligation
Fair value of assets
Funded status at end of year
Amounts Recognized in the Balance Sheet Consist of:
Other noncurrent liabilities
Net liability recognized
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net gain (loss)
Year Ended December 31,
2019
2018
615
—
7
25
—
(2)
(18)
93
(46)
674
669
490
—
—
—
(18)
102
(46)
528
$
$
$
$
$
(674) $
528
(146) $
(146) $
(146) $
163
502
15
21
(28)
—
—
(34)
(24)
615
611
128
428
12
(28)
—
(26)
(24)
490
(615)
490
(125)
(125)
(125)
(24) $
(13)
$
$
$
$
$
$
$
$
$
$
The following table provides information regarding pension plans with projected benefit obligation (PBO) and
accumulated benefit obligation (ABO) in excess of the fair value of plan assets.
Pension Plans with PBO and ABO in Excess Of Plan Assets:
Projected benefit obligations
Accumulated benefit obligation
Plan assets
Pension Plan Investment Strategy and Asset Allocations
December 31,
2019
2018
$
$
$
674
669
528
$
$
$
615
611
490
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit
obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held
primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities and money
market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities.
International equity securities are used to further diversify the equity portfolio and may include investments in both developed
and emerging markets.
143
The target asset allocation ranges of pension plan investments by asset category are as follows:
Asset Category:
Fixed income
Global equity securities
Real estate
Credit strategies
Target Allocation Ranges
Vistra Energy Plan
Dynegy Plan
EEI Plan
65 % - 75%
16 % - 24%
4 % - 8%
3 % - 7%
45 % - 55%
29 % - 37%
8 % - 12%
6 % - 10%
40 % - 50%
32 % - 41%
10 % - 14%
6 % - 10%
Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a
comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies.
The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset
class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the
diversification benefits of investing in multiple asset classes and potential benefits of employing active investment
management.
Asset Class:
Fixed income securities
Global equity securities
Real estate
Credit strategies
Weighted average
Retirement Plan
Expected Long-Term Rate of Return
Vistra Energy Plan
Dynegy Plan
EEI Plan
3.2 %
7.5 %
5.2 %
5.5 %
4.4 %
3.2 %
7.5 %
5.2 %
5.5 %
5.3 %
3.1 %
7.5 %
5.2 %
5.5 %
5.5 %
144
Fair Value Measurement of Pension Plan Assets
At December 31, 2019 and 2018, the Retirement Plan assets measured at fair value on a recurring basis consisted of the
following:
Asset Category:
Interest-bearing cash
Fixed income securities:
Corporate bonds (a)
Government bonds
Other (b)
Total assets categorized as Level 1 or 2
Assets measured at net asset value (c):
Cash commingled trusts
Equity securities:
Global equities
Fixed income securities:
Corporate bonds (a)
Government bonds
Other (d)
Real estate
December 31,
Level 1
2019
Level 2
Total
Level 1
2018
Level 2
Total
$
— $
— $
— $
— $
(6) $
(6)
—
—
—
—
—
—
—
—
—
—
—
—
10
169
211
50
37
51
528
528
57
—
—
57
61
25
6
86
118
25
6
143
18
192
137
—
—
—
347
490
$
Total assets measured at net asset value
Total assets
$
___________
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.
(b) Other consists primarily of taxable municipal bonds.
(c) Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified
in the fair value hierarchy. The fair value amounts presented in this line are intended to permit reconciliation of the fair
value hierarchy to total Vistra Retirement Plan assets.
(d) Consists primarily of high-yield bonds, emerging market debt, and bank loans.
145
Detailed Information Regarding Postretirement Benefits Other Than Pensions
The following OPEB information is based on a December 31, 2019 measurement date:
Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate (Vistra Energy Plan)
Discount rate (Oncor Plan)
Discount rate (Dynegy Plan)
Expected return on plan assets (EEI Union)
Expected return on plan assets (EEI Salaried)
Components of Net Postretirement Benefit Cost:
Service cost
Interest cost
Expected return on plan assets
Amortization of unrecognized amounts
Immediate postretirement benefit cost
Net periodic OPEB cost
Other Changes in Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income:
Net (gain) loss and prior service (credit) cost
Total recognized in net periodic benefit cost and other
comprehensive income
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate (Vistra Energy Plan)
Discount rate (Split-Participant Plan)
Discount rate (Dynegy Plan)
Expected return on plan assets (EEI Union)
Expected return on plan assets (EEI Salaried)
Year Ended December 31,
2019
2018
2017
4.35 %
— %
4.35 %
5.36 %
4.70 %
3.67 %
— %
4.04 %
5.10 %
4.47 %
4.11 %
4.18 %
— %
— %
— %
$
$
$
$
2
6
(1)
3
1
11
$
$
— $
11
$
2
5
(1)
3
—
9
$
$
(6) $
3
$
2
4
—
—
—
6
26
32
3.25 %
3.25 %
3.25 %
7.07 %
3.43 %
4.35 %
4.35 %
4.35 %
5.36 %
4.70 %
3.67 %
3.67 %
— %
— %
— %
For the year ended December 31, 2019, the net actuarial loss of $5 million was driven by losses attributable to decreasing
discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by
gains attributable to actual asset performance exceeding expectations, life expectancy changes, updates to health care related
assumptions and changes due to the repeal of certain Affordable Care Act fees.
For the year ended December 31, 2018, the net actuarial loss of $7 million was driven by gains attributable to increasing
discount rates due to changes in the corporate bond markets, life expectancy projection updates and updates to health care
related assumptions, partially offset by losses attributable to actual asset performance falling short of expectations and plan
experience different than expected.
For the period ended December 31, 2017, the net actuarial loss of $15 million was driven by losses attributable to
decreasing discount rates due to changes in the corporate bond markets, demographic assumption updates to reflect current
expectations and updates to health care related assumptions, partially offset by gains attributable to life expectancy projection
updates and plan experience different than expected.
146
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year
Acquisition
Service cost
Interest cost
Participant contributions
Plan amendments (a)
Curtailment
Actuarial (gain) loss
Benefits paid
Benefit obligation at end of year
Change in Plan Assets:
Fair value of assets at beginning of year
Acquisition
Employer contributions
Participant contributions
Benefits paid
Actual gain (loss) on assets
Fair value of assets at end of year
Funded Status:
Benefit obligation
Fair value of assets
Funded status at end of year
Amounts Recognized on the Balance Sheet Consist of:
Other noncurrent assets
Other current liabilities
Other noncurrent liabilities
Net liability recognized
Year Ended December 31,
2019
2018
144
—
2
6
3
—
(1)
10
(13)
151
29
—
9
3
(13)
6
34
$
$
$
$
(151) $
34
(117) $
$
18
(9) $
(126)
(117) $
115
37
2
5
2
4
—
(9)
(12)
144
—
32
8
2
(12)
(1)
29
(144)
29
(115)
14
(8)
(121)
(115)
$
$
$
$
$
$
$
$
$
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net loss and prior service cost
___________
(a) For the year ended December 31, 2018, plan amendments relate to changes in Dynegy plans and retiree medical cost
15
15
$
$
structure.
The following tables provide information regarding the assumed health care cost trend rates.
December 31, 2019
December 31, 2018
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year
Rate to which the cost trend is expected to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year (Vistra Energy Plan, EEI Union and
EEI Salaried)
Health care cost trend rate assumed for next year (Oncor Plan)
Rate to which the cost trend is expected to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
6.40 %
4.50 %
2029
8.60 %
8.30 %
4.50 %
2029
6.70 %
4.50 %
2026
9.90 %
9.90 %
4.50 %
2027
147
Fair Value Measurement of OPEB Plan Assets
At December 31, 2019 and 2018, the Vistra Energy OPEB plan assets measured at fair value on a recurring basis totaled
$34 million and $29 million, respectively, and consisted of $26 million and $21 million, respectively, of U.S equities classified
as Level 1 and $8 million and $8 million, respectively, of U.S. Treasuries classified as Level 2.
Significant Concentrations of Risk
The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize
return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing
capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be
diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There
are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio
weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond
yields and at December 31, 2019 consisted of 361 corporate bonds with an average rating of AA using Moody's, S&P and Fitch
ratings.
Contributions
Contributions to the Retirement Plan for the years ended December 31, 2019, 2018 and 2017 totaled zero, $12 million
and zero, respectively, and $26 million in contributions are expected to be made in 2020. OPEB plan funding for the years
ended December 31, 2019, 2018 and 2017 totaled $9 million, $8 million and $5 million, respectively, and funding in 2020 is
expected to total $9 million.
Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
Pension benefits
OPEB
Qualified Savings Plans
2020
2021
2022
2023
2024
2025-29
$
$
59
10
$
$
54
10
$
$
42
10
$
$
43
10
$
$
42
10
$
$
199
43
Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined
contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the
terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly
compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75%
of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such
threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in
an amount equal to 100% (75% for employees covered under the traditional 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 Energy assumed Dynegy's participant-directed defined contribution plan.
In January 2019,
this plan was merged into the Thrift Plan.
Aggregate employer contributions to the qualified savings plans totaled $27 million, $24 million and $19 million for the
years ended December 31, 2019, 2018 and 2017, respectively.
148
18. STOCK-BASED COMPENSATION
Vistra Energy 2016 Omnibus Incentive Plan
On the Effective Date, the Vistra Energy board of directors (Board) adopted the 2016 Omnibus Incentive Plan (2016
Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-
based awards to our non-employee directors, employees, and certain other persons. The Board or any committee duly
authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to,
among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of
shares that are to be subject to such awards and (c) establish the terms and conditions of awards, including the price (if any) to
be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock
options, RSUs, restricted stock, performance awards and other forms of awards granted or denominated in shares of Vistra
Energy common stock, as well as certain cash-based awards.
If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for
any reason without having been exercised in full, the number of shares of Vistra Energy common stock underlying any
unexercised award shall again be available for awards under the 2016 Incentive Plan.
If any shares of restricted stock,
performance awards or other stock-based awards denominated in shares of Vistra Energy common stock awarded under the
2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards
under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the
maximum share limitation.
As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the
2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets
under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers,
combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares
outstanding, and extraordinary dividends or distributions of property to the Vistra Energy stockholders.
Assumption of Dynegy Stock Compensation Plans
At the Merger Date, Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date
were generally automatically converted upon completion of the Merger into stock options and equity-based awards,
respectively, with respect to Vistra Energy's common stock, after giving effect to the Exchange Ratio.
Instrument Type
Dynegy Awards Prior to
the Merger Date
Vistra Awards Converted
at the Merger Date
Stock Options
Restricted Stock Units
Performance Units
Total
4,096,027
5,718,148
1,538,133
2,670,610 $
3,056,689
938,721
Fair Value of Awards (a)
10
61
18
89
$
____________
(a) $26 million was attributable to pre-combination service and considered part of the purchase price (see Note 2). $33
million was recognized immediately as compensation expense due to accelerated vesting as a result of the Merger. $30
million will be amortized as compensation expense over the remaining service period and is recorded in additional paid in
capital in the consolidated balance sheet.
Stock-Based Compensation Expense
Stock-based compensation expense is reported as SG&A in the statement of consolidated net income (loss) as follows:
Total stock-based compensation expense
Income tax benefit
Stock based-compensation expense, net of tax
Year Ended December 31,
2019
2018
2017
$
$
47
(9)
38
$
$
73
(15)
58
$
$
19
(7)
12
149
Stock Options
The fair value of each stock option is estimated on the date of grant using a Black-Scholes option-pricing model. The
risk-free interest rate used in the option valuation model was based on yields available on the grant dates for U.S. Treasury
Strips with maturity consistent with the expected life assumption. The expected term of the option represents the period of time
that options granted are expected to be outstanding and is based on the SEC Simplified Method (midpoint of average vesting
time and contractual term). Expected volatility is based on an average of the historical, daily volatility of a peer group selected
by Vistra Energy over a period consistent with the expected life assumption ending on the grant date. We assumed no dividend
yield in the valuation of the options granted from 2016-2018 and assumed a 1.9% dividend yield in the valuation of options
granted in 2019. These options may be exercised over either three- or four-year graded vesting periods and will expire 10 years
from the grant date.
The 2016 Incentive Plan includes an anti-dilutive provision that requires any outstanding option awards to be adjusted for
the effect of equity restructurings.
In March 2017, the Board declared that the exercise price of each outstanding option be
reduced by $2.32, the amount per share of common stock related to a special dividend approved by the Board in December
2016 (see Note 14).
Issuance of Merger-related Stock Options — At the Merger Date, we issued 5.2 million stock options to certain members
of management, which are subject to performance and service conditions for vesting. The performance condition is based on
the Company's achievement of certain merger related targets which were achieved as of December 31, 2019. Compensation
cost was recognized in 2018 and 2019 based on graded vesting over 4 and 5 years since the date of issuance because we
estimated achievement of the target was likely to occur.
Stock options outstanding at December 31, 2019 are all held by current employees. The following table summarizes our
stock option activity:
Year Ended December 31, 2019
Total outstanding at beginning of period
Granted
Exercised
Forfeited or expired
Total outstanding at end of period
Weighted
Average
Stock Options
Exercise Price
(in thousands)
17.97
$
14,499
26.32
2,103
$
13.93
(1,467) $
26.20
(1,600) $
18.73
$
13,535
Exercisable at December 31, 2019
4,601
$
16.14
Weighted Average
Remaining Contractual
Term (Years)
7.3
7.3
6.6
Aggregate
Intrinsic Value
(in millions)
$
$
$
85.1
69.3
36.6
At December 31, 2019, $37 million of unrecognized compensation cost related to unvested stock options granted under
the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 3 years.
Restricted Stock Units
The following table summarizes our restricted stock unit activity:
Total outstanding at beginning of period
Granted
Exercised
Forfeited or expired
Total outstanding at end of period
Expected to vest
Year Ended December 31, 2019
Weighted
Restricted Stock
Average Grant
Units
Date Fair Value
(in thousands)
16.77
$
3,226
26.43
$
989
18.20
(1,480) $
20.12
(197) $
20.99
$
2,538
2,485
$
21.37
Weighted Average
Remaining Contractual
Term (Years)
1.1
0.8
0.8
Aggregate
Intrinsic Value
(in millions)
$
$
$
73.8
57.2
56.1
At December 31, 2019, $32 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.
150
Performance Stock Units
In October 2017, we issued Performance Stock Units (PSUs) to certain members of management. As of December 31,
2019, we had not yet established the significant terms of the PSUs relevant to vesting (scorecard, thresholds, and targets) for the
entire measurement period; therefore, a grant date for financial accounting purposes had not occurred. In February 2020, the
final terms were established and a grant date for financial accounting purposes has occurred. Beginning March 2020,
compensation cost will be recognized ratably over the remaining 13-month vesting period.
In February 2019 and February 2020, we issued Performance Stock Units (PSUs) to certain members of management. As
of December 31, 2019, we had not yet established the significant terms of the PSUs relevant to vesting (scorecard, thresholds,
and targets) for the entire measurement period; therefore, a grant date for financial accounting purposes had not occurred.
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 Rights in exchange for their claims.
Registration Rights Agreement
Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the
Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra Energy
common stock held by such selling stockholders.
In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra
Energy common stock held by certain significant stockholders pursuant to the Registration Rights Agreement, which was
declared effective by the SEC in May 2017. The registration statement was amended in March 2018. Pursuant to the
Registration Rights Agreement, in June 2018, we filed a post-effective amendment to the Form S-1 registration statement on
Form S-3, which was declared effective by the SEC in July 2018. Among other things, under the terms of the Registration
Rights Agreement:
•
•
if we propose to file certain types of registration statements under the Securities Act with respect to an offering of
equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration
Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the
Registration Rights Agreement; and
the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file
registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of
all or part of their respective shares of Vistra Energy common stock (a Demand Registration), and the Company is
required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly
and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days,
in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling
stockholders to effectuate the Demand Registration (as defined in the Registration Rights Agreement) and (b) to
become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed.
All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by
or on behalf of the selling stockholders, will be paid by us. Legal fee expenses paid or accrued by Vistra Energy on behalf of
the selling stockholders totaled less than $1 million during each of the years ended December 31, 2019, 2018 and 2017.
Tax Receivable Agreement
On the Effective Date, Vistra Energy entered into the TRA with a transfer agent on behalf of certain former first-lien
creditors of TCEH. See Note 8 for discussion of the TRA.
151
Share Repurchase Transaction
In November 2018, the disinterested members of the Board considered and approved (in accordance with the Company's
corporate governance guidelines) a share repurchase transaction, whereby Apollo Management Holdings L.P. (Apollo) and the
Company, in a privately negotiated transaction, agreed for the Company to directly repurchase 5 million shares from Apollo.
This purchase was part of Apollo's larger, 17 million share block trade, with the remaining 12 million shares being sold in a
separate unregistered Rule 144 secondary block trade to a broker-dealer, who placed all 12 million shares with institutional
investors. The Company repurchased the 5 million shares at the same discounted price (discounted from the November 19,
2018 closing price) that the participating broker paid for the 12 million shares it purchased, and the Company did not pay any
additional fees to Apollo or the participating broker for the 5 million shares it repurchased.
20. SEGMENT INFORMATION
The operations of Vistra Energy are aligned into six reportable business segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv)
NY/NE, (v) MISO and (vi) Asset Closure. Our chief operating decision maker reviews the results of these segments separately
and allocates resources to the respective segments as part of our strategic operations. Operational results for four facilities
retired in late 2019 were recast from the MISO segment to the Asset Closure segment (see Note 4).
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 Energy, Value Based Brands, Dynegy
Energy Services, Homefield Energy, TriEagle Energy, Public Power and US Gas & Electric across 19 states in the U.S.
The ERCOT, PJM, NY/NE (comprising NYISO and ISO-NE) and MISO segments are engaged in electricity generation,
wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management,
all largely within their respective RTO/ISO market. The PJM, NY/NE and MISO segments were established on the Merger
Date to reflect markets served by businesses acquired in the Merger. Prior to the Merger, the ERCOT segment was referred to
as the Wholesale Generation segment.
As discussed in Note 1, the Asset Closure segment was established effective January 1, 2018. The Asset Closure segment
is engaged in the decommissioning and reclamation of retired plants and mines (see Note 4). Separately reporting the Asset
Closure segment provides management with better information related to the performance and earnings power of Vistra
Energy's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and
reclamation of retired plants and mines. We have not allocated any unrealized gains or losses on the commodity risk
management activities to the Asset Closure segment for the generation plants that were retired in 2018 and 2019.
Corporate and Other represents the remaining non-segment operations consisting primarily of (i) general corporate
expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating
segments and (ii) CAISO operations.
Except as noted in Note 1, the accounting policies of the business segments are the same as those described in the
summary of significant accounting policies in Note 1. Our chief operating decision maker uses more than one measure to
assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net
income (loss) prepared based on 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.
152
For the year ended
Retail
ERCOT
PJM
NY/NE
MISO
Asset
Closure
Corporate
and Other (b) Eliminations Consolidated
Operating revenues (a):
December 31, 2019
December 31, 2018
December 31, 2017
Depreciation and
amortization:
December 31, 2019
December 31, 2018
December 31, 2017
Operating income
(loss):
$ 6,872
5,597
4,058
$ 3,993
2,634
1,794
$ 2,442
1,725
—
$ 1,135
817
—
$ 658
399
—
$ 341
371
964
$
$
338
208
—
(3,970) $
(2,607)
(1,386)
11,809
9,144
5,430
$ (292) $ (508) $ (537) $ (208) $
(318)
(430)
(416)
(229)
(413)
—
(152)
—
(19) $ — $
(9)
—
—
(1)
(76) $
(86)
(40)
— $
—
1
(1,640)
(1,394)
(699)
December 31, 2019
December 31, 2018
December 31, 2017
$ 155
690
461
$ 1,340
(70)
(118)
$ 412
100
—
$
179
70
—
$
52
49
—
$ (107) $
(63)
(68)
(38) $
(281)
(78)
— $
(4)
1
1,993
491
198
Interest expense and
related charges:
December 31, 2019
December 31, 2018
December 31, 2017
$
(21) $
(7)
—
$
8
(12)
(21)
(10) $
(8)
—
(3) $
(2)
—
(4) $ — $
(1)
—
—
—
(770) $
(613)
(252)
Income tax (expense)
benefit:
December 31, 2019
December 31, 2018
December 31, 2017
Net income (loss):
$ — $ — $ — $ — $ — $ — $
—
—
—
4
—
—
December 31, 2019
December 31, 2018
December 31, 2017
$ 134
712
495
$ 1,368
(55)
(114)
$ 405
100
—
Capital expenditures, including nuclear fuel and
excluding LTSA prepayments:
December 31, 2019
December 31, 2018
December 31, 2017
$
$
1
1
—
$
299
283
150
69
41
—
$
$
—
—
188
79
—
22
10
—
$
$
—
—
55
48
—
25
3
—
—
—
(290) $
45
(509)
$ (109) $
(62)
(63)
(1,115) $
(876)
(573)
$ — $
—
—
$
71
58
26
$
3
71
80
— $
—
1
— $
(2)
1
— $
—
—
(797)
(572)
(193)
(290)
45
(504)
926
(56)
(254)
487
396
176
____________
(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, 2019
December 31, 2018
December 31, 2017
Retail
8
$
(12)
18
ERCOT
$ 575
(483)
(305)
PJM
$ 237
(50)
—
$
NY/NE MISO
24
$ 102
3
(40)
—
—
Asset
Closure
$ — $
—
—
Corporate
and Other
41
(15)
—
Eliminations
(1)
Consolidated
$
(305) $
217
154
682
(380)
(133)
____________
(1) Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated
results.
(b) Other includes CAISO operations.
Income tax expense is not reflected in net income of the segments but is reflected
entirely in Corporate and Other net income.
153
As of
Retail
ERCOT
PJM
NY/NE
MISO
Asset
Closure
Corporate and
Other and
Eliminations
Consolidated
Total assets:
December 31, 2019
December 31, 2018
$ 10,399
7,699
$ 10,425
9,347
$ 5,941
7,188
$ 3,060
2,722
$
$
47
544
$
345
546
(3,601) $
(2,022)
26,616
26,024
21. SUPPLEMENTARY FINANCIAL INFORMATION
Interest Expense
Interest paid/accrued
Unrealized mark-to-market net (gains) losses on interest rate swaps
Amortization of debt issuance costs, discounts and premiums
Debt extinguishment (gain) loss
Capitalized interest
Other
Total interest expense and related charges
Year Ended December 31,
2019
2018
2017
576
220
9
(21)
(12)
25
797
$
$
537
5
—
27
(12)
15
572
$
$
213
(29)
4
—
(7)
12
193
$
$
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest
rate swaps discussed in Note 11, was 4.03%, 4.24% and 4.38% at December 31, 2019, 2018 and 2017, respectively.
Other Income and Deductions
Other income:
Office space sublease rental income (a)
Sale of land (b)
Funds released from escrow to settle pre-petition claims of our
predecessor
Insurance settlement (b)
Interest income
All other
Total other income
Other deductions:
Write-off of generation equipment (b)
Curtailment expense (Note 4) (c)
All other
Total other deductions
Year Ended December 31,
2019
2018
2017
$
$
$
— $
—
9
22
10
15
56
—
3
12
15
$
$
8
3
—
16
18
2
47
—
—
5
5
$
$
$
11
4
—
—
15
7
37
2
—
3
5
____________
(a) Reported in Corporate and Other non-segment. Beginning January 1, 2019, our sublease rental income related to real
estate leases is reported in SG&A expenses in the consolidated statements of operations.
(b) Reported in ERCOT segment.
(c) Reported in Asset Closure segment.
154
Restricted Cash
December 31, 2019
December 31, 2018
Current
Assets
Noncurrent
Assets
Current
Assets
Noncurrent
Assets
Amounts related to remediation escrow accounts
Amounts related to restructuring escrow accounts
Amounts related to Ambit customer deposits
Amounts related to Ambit commodity trading agreement
Amounts related to Ambit letters of credit (Note 11)
Total restricted cash
$
$
15
43
19
62
8
147
$
$
28
—
—
—
—
28
$
$
— $
57
—
—
—
57
$
—
—
—
—
—
—
Remediation Escrow — During the year ended December 31, 2019, Vistra Energy transferred asset retirement obligations
related to several closed plant sites to a third-party remediation company. As part of the transfers, Vistra Energy funded
approximately $43 million into escrow accounts, and the funds are released to the remediation company as milestones are
reached in the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations
are included in other current liabilities and other noncurrent liabilities and deferred credits.
Pre-Petition Claims — On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged
from the Chapter 11 Cases and discharged approximately $33.8 billion in liabilities subject to compromise. Initial distributions
related to the allowed claims asserted against the TCEH Debtors and the Contributed EFH Debtors commenced subsequent to
the Effective Date. As of December 31, 2019, the TCEH Debtors held approximately $43 million in escrow to (1) distribute to
holders of contingent and/or disputed unsecured claims that become allowed and/or (2) make further distributions to holders of
previously allowed unsecured claims, if applicable.
In December 2019, the Bankruptcy court entered an order, Docket No.
13982, sustaining the TCEH Debtors' objection to and liquidating the manifested and unmanifested asbestos claims. As of this
filing, the TCEH Debtors believe they have resolved the remaining contingent and/or disputed unsecured claims, and are
undertaking the necessary steps to modify the claims register accordingly and make a final distribution from the escrow to
holders of allowed claims in the near term. The claims that remained unresolved as of December 31, 2019 and the related
escrow balance are recorded in Vistra Energy's consolidated balance sheet as other current liabilities and current restricted cash,
respectively. All non-priority unsecured claims, including asbestos claims arising before the Petition Date, will be satisfied
solely from the approximately $43 million in escrow.
Trade Accounts Receivable
Wholesale and retail trade accounts receivable
Allowance for uncollectible accounts
Trade accounts receivable — net (a)
December 31,
2019
2018
$
$
1,401
(36)
1,365
$
$
1,106
(19)
1,087
____________
(a) At December 31, 2019, includes $175 million of trade accounts receivable related to operations acquired in the Ambit and
Crius Transactions.
Gross trade accounts receivable at December 31, 2019 and 2018 included unbilled retail revenues of $494 million and
$350 million, respectively.
Allowance for Uncollectible Accounts Receivable
Allowance for uncollectible accounts receivable at beginning of period
Increase for bad debt expense
Decrease for account write-offs
Allowance for uncollectible accounts receivable at end of period
Year Ended December 31,
2019
2018
2017
$
$
19
82
(65)
36
$
$
14
56
(51)
19
$
$
10
43
(39)
14
155
Inventories by Major Category
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
Total investments
Investment in Unconsolidated Subsidiary
December 31,
2019
2018
278
172
19
469
$
$
286
115
11
412
December 31,
2019
2018
1,451
37
49
1,537
$
$
1,170
31
49
1,250
$
$
$
$
On the Merger Date, we assumed Dynegy's 50% interest in Northeast Energy, LP (NELP), a joint venture with NextEra
Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At December 31, 2019 and 2018,
our investment in NELP totaled $123 million and $129 million, respectively. Our risk of loss related to our equity method
investment is limited to our investment balance.
Equity earnings related to our investment in NELP totaled $14 million and $17 million for the years ended December 31,
2019 and 2018, respectively, recorded in equity in earnings of unconsolidated investment in our consolidated statements of
operations. We received distributions totaling $22 million and $17 million for the years ended December 31, 2019 and 2018,
respectively.
In December 2019, Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc.,
indirect
subsidiaries of Vistra Energy, entered into a transaction agreement with NELP wherein the indirect subsidiaries of Vistra will
redeem their ownership interest in the NELP partnership in exchange for 100% ownership interest in New Jersey Energy
Associates, the holding company which owns the Sayreville facility. As a result of the agreement, Vistra will indirectly own
100% of the Sayreville facility and will no longer have an ownership interest in the Bellingham NEA facility. The agreement
was approved by FERC on February 25, 2020, and the transaction is expected to close on March 2, 2020.
156
Nuclear Decommissioning Trust
Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are
carried at fair value. Decommissioning costs are being recovered from Oncor customers as a delivery fee surcharge over the
life of the plant and deposited by Vistra Energy (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund.
Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liability, are
offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent
liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. If funds recovered
from Oncor's customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear
generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra
Energy, provided that Vistra Energy complied with PUCT rules and regulations regarding decommissioning trusts. A summary
of the fair market value of investments in the fund follows:
Year Ended December 31,
2019
2018
$
521
930
1,451
443
727
1,170
Debt securities (a)
Equity securities (b)
$
Total
____________
(a) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio
rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with government
and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of 3.42% and
3.69% at December 31, 2019 and 2018, respectively, and an average maturity of 9 years and 8 years at December 31,
2019 and 2018, respectively.
$
$
(b) The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500
Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments.
Debt securities held at December 31, 2019 mature as follows: $170 million in one to five years, $147 million in five to 10
years and $204 million after 10 years.
The following table summarizes proceeds from sales of securities and investments in new securities.
Proceeds from sales of securities
Investments in securities
Property, Plant and Equipment
Power generation and structures
Land
Office and other equipment
Total
Less accumulated depreciation
Net of accumulated depreciation
Year Ended December 31,
2019
2018
2017
$
$
431
$
(453) $
252
$
(274) $
252
(272)
December 31,
2019
2018
15,205
622
164
15,991
(2,553)
13,438
59
197
220
13,914
$
$
14,604
642
182
15,428
(1,284)
14,144
—
191
277
14,612
$
$
Finance lease right-of-use assets
Nuclear fuel (net of accumulated amortization of $216 million and $189 million)
Construction work in progress
Property, plant and equipment — net
Depreciation expenses totaled $1.300 billion, $1.024 billion and $236 million for the years ended December 31, 2019,
2018 and 2017, respectively.
157
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 34 years for our property, plant and equipment.
Asset Retirement and Mining Reclamation Obligations (ARO)
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining,
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 recoverable through the regulatory process as part of
delivery fees charged by Oncor. We have also identified conditional AROs for asbestos removal and disposal, which are
specific to certain generation assets. However, because the period of remediation is indeterminable no removal liabilities have
been recognized.
At December 31, 2019, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled
$1.320 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 recoverable 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 $131 million in other
noncurrent liabilities and deferred credits.
158
The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in
our consolidated balance sheets, for the years ended December 31, 2019, 2018 and 2017:
Liability at December 31, 2016
Additions:
Accretion
Adjustment for change in estimates (a)
Incremental reclamation costs (b)
Reductions:
Payments
Liability at December 31, 2017
Additions:
Accretion
Adjustment for change in estimates
Obligations assumed in the Merger
Reductions:
Payments
Liability at December 31, 2018
Additions:
Accretion
Adjustment for change in estimates
Adjustment for obligations assumed through
acquisitions
Reductions:
Payments
Liability transfers (c)
Liability at December 31, 2019
Less amounts due currently
Nuclear Plant
Decommissioning
1,200
33
—
—
—
1,233
43
—
—
—
1,276
44
—
—
Mining Land
Reclamation
Coal Ash and
Other
375
18
81
—
(36)
438
22
56
2
(76)
442
22
16
—
151
8
44
62
—
265
28
(89)
475
(24)
655
31
(1)
(3)
Total
1,726
59
125
62
(36)
1,936
93
(33)
477
(100)
2,373
97
15
(3)
—
—
1,320
—
1,320
(70)
—
410
(89)
321
(39)
(135)
508
(52)
456
(109)
(135)
2,238
(141)
2,097
Noncurrent liability at December 31, 2019
____________
(a) Amounts primarily relate to the impacts of accelerating the ARO associated with the retirements of the Sandow 4, Sandow
$
$
$
$
5, Big Brown and Monticello plants (see Note 4).
(b) Amounts primarily relate to liabilities incurred as part of acquiring certain real property through the Alcoa contract
settlement (see Note 4).
(c) Represents ARO transferred to a third-party for remediation. Any remaining unpaid third-party obligation has been
reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance
sheets.
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
Retirement and other employee benefits
Identifiable intangible liabilities (Note 6)
Regulatory liability
Finance lease liabilities
Uncertain tax positions, including accrued interest
Liability for third-party remediation
Other accrued expenses
Total other noncurrent liabilities and deferred credits
159
December 31,
2019
2018
$
$
295
286
131
78
10
41
148
989
$
$
270
401
—
—
4
—
66
741
Fair Value of Debt
Long-term debt (see Note 11):
Long-term debt under the Vistra Operations
Credit Facilities
Vistra Operations Senior Notes
Vistra Energy Senior Notes
7.000% Amortizing Notes
Forward Capacity Agreements
Equipment Financing Agreements
Mandatorily redeemable subsidiary preferred
stock
Building Financing
Other debt
December 31, 2019
December 31, 2018
Fair Value
Hierarchy
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
$
Level 2
Level 2
Level 2
Level 2
Level 3
Level 3
Level 2
Level 2
Level 3
$
2,715
6,620
774
—
155
87
—
16
12
$
2,717
6,926
772
—
155
87
—
16
12
$
5,820
987
3,819
23
221
102
70
23
—
5,599
963
3,765
24
221
102
70
21
—
We 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.
Supplemental Cash Flow Information
The following table reconciles cash, cash equivalents and restricted cash reported in our consolidated statements of cash
flows to the amounts reported in our balance sheets at December 31, 2019 and 2018:
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,
2019
2018
300
147
28
475
$
$
636
57
—
693
$
$
The following table summarizes our supplemental cash flow information for the years ended December 31, 2019, 2018
and 2017, respectively.
Cash payments related to:
Interest paid
Capitalized interest
Interest paid (net of capitalized interest)
Income taxes paid / (refunds received) (a)
Noncash investing and financing activities:
Construction expenditures (b)
Shares issued for tangible equity unit contracts (Note 14)
Land transferred with liability transfers
Vistra Energy common stock issued in the Merger (Notes 2 and 14)
Year Ended December 31,
2019
2018
2017
$
$
$
$
$
$
$
$
525
(12)
513
$
(76) $
$
50
$
446
16
$
— $
651
(12)
639
67
$
$
$
$
79
— $
— $
$
2,245
245
(7)
238
63
12
—
—
—
____________
(a) For the year ended December 31, 2019, we paid state income taxes of $39 million and received federal tax refunds of
$115 million.
(b) Represents end-of-period accruals for ongoing construction projects.
160
Quarterly Information (Unaudited)
Unaudited results of operations by quarter are summarized below. In our opinion, all adjustments (consisting of normal
recurring accruals) necessary for a fair statement of such amounts have been made. Quarterly results are not necessarily
indicative of a full year's operations because of seasonal and other factors. Quarterly amounts may not add to full year amounts
due to rounding.
March 31
June 30
September 30
December 31
Quarter Ended
2019 (a):
Operating revenues
Operating income
Net income
Net income attributable to Vistra Energy
Net income per weighted average share of common stock
outstanding — basic
Net income per weighted average share of common stock
outstanding — diluted
$
$
$
$
$
$
2,923
490
224
225
0.45
0.44
$
$
$
$
$
$
2,832
729
354
356
0.71
0.70
$
$
$
$
$
$
3,194
440
114
113
0.23
0.23
$
$
$
$
$
$
2,860
334
234
234
0.49
0.49
2018 (b):
Operating revenues
Operating income (loss)
Net income (loss)
Net income (loss) attributable to Vistra Energy
Net income (loss) per weighted average share of common
stock outstanding — basic
Net income (loss) per weighted average share of common
stock outstanding — diluted
____________
(a) For the year ended December 31, 2019, reflects the results of operations acquired in the Crius and Ambit Transactions.
(b) For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.
765
$
(394) $
(306) $
(306) $
3,243
650
331
330
2,574
231
105
108
(0.71) $
(0.71) $
$
$
$
$
$
$
$
$
$
$
$
$
0.61
0.21
0.62
0.20
$
$
$
$
$
$
2,562
4
(186)
(186)
(0.35)
(0.35)
161
22. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Our senior unsecured notes are guaranteed by substantially all of our wholly owned subsidiaries. The following
condensed consolidating financial statements present the financial information of (i) Vistra Energy Corp. (Parent), which is the
ultimate parent company and issuer of the senior notes with effect as of the Merger Date, on a stand-alone, unconsolidated
basis, (ii) the guarantor subsidiaries of Vistra Energy (Guarantor Subsidiaries), (iii) the non-guarantor subsidiaries of Vistra
Energy (Non-Guarantor Subsidiaries) and (iv) the eliminations necessary to arrive at the information for Vistra Energy on a
consolidated basis. The Guarantor Subsidiaries consist of the wholly owned subsidiaries, which jointly, severally, fully and
unconditionally, guarantee the payment obligations under the senior notes. See Note 11 for discussion of the senior notes.
These statements should be read in conjunction with the consolidated financial statements and notes thereto of Vistra
Energy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and
regulations for condensed financial information and does not include all disclosures included in annual financial statements.
The inclusion of Vistra Energy's subsidiaries as either Guarantor Subsidiaries or Non-Guarantor Subsidiaries in the condensed
consolidating financial information is determined as of the most recent balance sheet date presented.
The parent files a consolidated U.S. federal income tax return. All consolidated income tax expense or benefits and
deferred tax assets and liabilities have been allocated to the respective subsidiary columns in accordance with the accounting
rules that apply to separate financial statements of subsidiaries. In prior years, the Company had presented condensed financial
information of the Parent in Schedule I under Item 15; for purposes of that schedule, consolidated income tax expense or
benefits was reflected at the Parent.
Parent received $3.890 billion, $4.668 billion and $1.505 billion in dividends from its consolidated subsidiaries in the
years ended December 31, 2019, 2018 and 2017, respectively.
Condensed Consolidating Statements of Operations
for the Year Ended December 31, 2019
(Millions of Dollars)
Non-
Guarantor
Subsidiaries
528
$
(297)
(65)
(82)
(115)
(31)
1
—
(27)
—
—
(57)
13
—
(44)
2
(42) $
$
Eliminations
$
(291) $
168
—
—
124
1
(8)
—
7
—
—
—
—
(1,026)
(1,026)
—
(1,026) $
Consolidated
11,809
(5,742)
(1,530)
(1,640)
(904)
1,993
56
(15)
(797)
(37)
16
1,216
(290)
—
926
2
928
$
Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Operating income (loss)
Other income
Other deductions
Interest expense and related charges
Impacts of Tax Receivable Agreement
Equity in earnings of unconsolidated investment
Income (loss) before income taxes
Income tax (expense) benefit
Equity in earnings (loss) of subsidiaries, net of tax
Net income (loss)
Net loss attributable to noncontrolling interest
Net income (loss) attributable to Vistra Energy
$
Parent
(Issuer)
Guarantor
Subsidiaries
11,572
(5,613)
(1,465)
(1,551)
(851)
2,092
51
(15)
(689)
—
16
1,455
(345)
(42)
1,068
—
1,068
— $
—
—
(7)
(62)
(69)
12
—
(88)
(37)
—
(182)
42
1,068
928
—
928
$
162
Condensed Consolidating Statements of Operations
for the Year Ended December 31, 2018
(Millions of Dollars)
$
Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Operating income (loss)
Other income
Other deductions
Interest expense and related charges
Impacts of Tax Receivable Agreement
Equity in earnings of unconsolidated investment
Income (loss) before income taxes
Income tax (expense) benefit
Equity in earnings (losses) of subsidiaries, net of tax
Net income (loss)
Net loss attributable to noncontrolling interest
Net income (loss) attributable to Vistra Energy
$
$
Parent
(Issuer)
Guarantor
Subsidiaries
9,043
(4,968)
(1,255)
(1,337)
(660)
823
41
(6)
(309)
—
17
566
(284)
(25)
257
—
257
— $
—
—
—
(266)
(266)
9
—
(257)
(79)
—
(593)
282
257
(54) $
—
(54) $
Non-
Guarantor
Subsidiaries
174
$
(92)
(42)
(57)
(49)
(66)
—
1
(9)
—
—
(74)
47
—
(27) $
2
(25) $
$
$
Eliminations
$
Consolidated
9,144
(5,036)
(1,297)
(1,394)
(926)
491
47
(5)
(572)
(79)
17
(101)
45
—
(56)
2
(54)
(73) $
24
—
—
49
—
(3)
—
3
—
—
—
—
(232)
(232) $
—
(232) $
Condensed Consolidating Statements of Operations
for the Year Ended December 31, 2017
(Millions of Dollars)
Operating revenues
Fuel, purchased power costs and delivery fees
Operating costs
Depreciation and amortization
Selling, general and administrative expenses
Impairment of long-lived assets
Operating income (loss)
Other income
Other deductions
Interest expense and related charges
Impacts of Tax Receivable Agreement
Income before income taxes
Income tax (expense) benefit
Equity in earnings (losses) of subsidiaries, net of tax
Net income (loss)
$
$
Parent
(Issuer)
Non-
Guarantor
Subsidiaries
$
Eliminations
Guarantor
Subsidiaries
5,430
(2,935)
(973)
(699)
(553)
(25)
245
33
(5)
(193)
—
80
(584)
—
(504) $
— $
—
—
—
(47)
—
(47)
4
—
—
213
170
80
(504)
(254) $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
— $
Consolidated
5,430
(2,935)
(973)
(699)
(600)
(25)
198
37
(5)
(193)
213
250
(504)
—
(254)
— $
—
—
—
—
—
—
—
—
—
—
—
—
504
504
$
163
Condensed Consolidating Statements of Comprehensive Income (Loss)
for the Year Ended December 31, 2019
(Millions of Dollars)
Net income (loss)
$
928
$
1,068
$
(44) $
(1,026) $
926
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement
benefit obligations
Total other comprehensive income
Comprehensive income (loss)
Comprehensive loss attributable to noncontrolling
interest
Comprehensive income (loss) attributable to Vistra
Energy
—
—
928
—
(8)
(8)
1,060
—
—
—
(44)
2
—
—
(1,026)
—
(8)
(8)
918
2
$
928
$
1,060
$
(42) $
(1,026) $
920
Condensed Consolidating Statements of Comprehensive Income (Loss)
for the Year Ended December 31, 2018
(Millions of Dollars)
Net income (loss)
$
(54) $
257
$
(27) $
(232) $
(56)
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement
benefit obligations
Adoption of accounting standard
Total other comprehensive income
Comprehensive income (loss)
Comprehensive loss attributable to noncontrolling
interest
Comprehensive income (loss) attributable to Vistra
Energy
$
$
—
1
1
(6)
—
(6)
—
—
—
—
—
—
(53) $
251
$
(27) $
(232) $
—
—
2
—
(6)
1
(5)
(61)
2
(53) $
251
$
(25) $
(232) $
(59)
Condensed Consolidating Statements of Comprehensive Income (Loss)
for the Year Ended December 31, 2017
(Millions of Dollars)
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Net income (loss)
$
(254) $
(504) $
— $
504
$
(254)
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement
benefit obligations
Total other comprehensive income
Comprehensive income (loss)
(23)
(23)
(29)
(29)
—
—
29
29
$
(277) $
(533) $
— $
533
$
(23)
(23)
(277)
164
Condensed Consolidating Statements of Cash Flows
for the Year Ended December 31, 2019
(Millions of Dollars)
Cash flows — operating activities:
Cash provided by (used in) operating activities
$
(58) $
2,702
$
92
$
— $
2,736
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Cash flows — investing activities:
Capital expenditures, including LTSA prepayments
Nuclear fuel purchases
Development and growth expenditures
Ambit acquisition (net of cash acquired)
Crius acquisition (net of cash acquired)
Proceeds from sales of nuclear decommissioning trust
fund securities
Investments in nuclear decommissioning trust fund
securities
Proceeds from sales of environmental allowances
Purchases of environmental allowances
Dividend received from subsidiaries
Other, net
Cash provided by (used in) investing activities
Cash flows — financing activities:
Issuances of long-term debt
Repayments/repurchases of debt
Net borrowings under accounts receivable
securitization program
Borrowings under Revolving Credit Facility
Repayments under Revolving Credit Facility
Debt tender offer and other financing fees
Stock repurchase
Cash dividends paid
Other, net
Cash provided by (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
(36)
—
—
—
—
—
—
—
—
3,890
—
3,854
—
(2,903)
—
—
—
(123)
(656)
(243)
—
(3,925)
(129)
(471)
(89)
(104)
(506)
(374)
431
(453)
197
(321)
—
23
(1,667)
6,507
(4,139)
—
650
(300)
(80)
—
(3,890)
6
(1,246)
(211)
228
453
(13)
—
—
—
—
—
—
—
(1)
—
—
(14)
—
(67)
111
—
—
—
—
—
—
44
122
12
—
—
—
—
—
—
—
—
—
(3,890)
—
(3,890)
—
—
—
—
—
—
—
3,890
—
3,890
—
—
$
99
$
242
$
134
$
— $
(520)
(89)
(104)
(506)
(374)
431
(453)
197
(322)
—
23
(1,717)
6,507
(7,109)
111
650
(300)
(203)
(656)
(243)
6
(1,237)
(218)
693
475
165
Condensed Consolidating Statements of Cash Flows
for the Year Ended December 31, 2018
(Millions of Dollars)
Cash flows — operating activities:
Cash provided by (used in) operating activities
$
(125) $
1,917
$
(321) $
— $
1,471
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Cash flows — investing activities:
Capital expenditures, including LTSA prepayments
Nuclear fuel purchases
Development and growth expenditures
Cash acquired in the Merger
Proceeds from sales of nuclear decommissioning trust
fund securities
Investments in nuclear decommissioning trust fund
securities
Proceeds from sales of environmental allowances
Purchases of environmental allowances
Dividend received from subsidiaries
Other, net
Cash provided by (used in) investing activities
Cash flows — financing activities:
Issuances of long-term debt
Repayments/repurchases of debt
Borrowings under accounts receivable securitization
program
Cash dividends paid
Debt tender offer and other financing fees
Stock repurchase
Other, net
Cash provided by (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
(24)
—
—
—
—
—
—
—
4,668
(1)
4,643
—
(4,543)
—
—
(179)
(763)
12
(5,473)
(955)
(351)
(118)
(31)
445
252
(274)
1
(5)
—
11
(70)
1,000
1,468
—
(4,668)
(57)
—
—
(2,257)
(410)
1,183
863
(3)
—
(3)
—
—
—
—
—
—
—
(6)
—
—
339
—
—
—
—
339
12
—
—
—
—
—
—
—
—
—
(4,668)
—
(4,668)
—
—
—
4,668
—
—
—
4,668
—
—
(378)
(118)
(34)
445
252
(274)
1
(5)
—
10
(101)
1,000
(3,075)
339
—
(236)
(763)
12
(2,723)
(1,353)
2,046
$
228
$
453
$
12
$
— $
693
166
Condensed Consolidating Statements of Cash Flows
for the Year Ended December 31, 2017
(Millions of Dollars)
Cash flows — operating activities:
Cash provided by (used in) operating activities
$
(108) $
1,494
$
— $
— $
1,386
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Cash flows — investing activities:
Capital expenditures
Nuclear fuel purchases
Development and growth expenditures
Odessa acquisition
Proceeds from sales of nuclear decommissioning trust
fund securities
Investments in nuclear decommissioning trust fund
securities
Proceeds from sales of environmental allowances
Purchases of environmental allowances
Dividend received from subsidiaries
Other, net
Cash provided by (used in) investing activities
Cash flows — financing activities:
Repayments/repurchases of debt
Cash dividend paid
Debt financing fees
Other, net
Cash provided by (used in) financing activities
—
—
—
(330)
—
—
—
—
1,505
—
1,175
—
—
—
—
—
Net change in cash, cash equivalents and restricted cash
1,067
(114)
(62)
(190)
(25)
252
(272)
1
(3)
—
16
(397)
(191)
(1,505)
(8)
(2)
(1,706)
(609)
Cash, cash equivalents and restricted cash — beginning
balance
Cash, cash equivalents and restricted cash — ending
balance
116
1,472
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,505)
—
(1,505)
—
1,505
—
—
1,505
—
—
(114)
(62)
(190)
(355)
252
(272)
1
(3)
—
16
(727)
(191)
—
(8)
(2)
(201)
458
1,588
$
1,183
$
863
$
— $
— $
2,046
167
Condensed Consolidating Balance Sheet
as of December 31, 2019
(Millions of Dollars)
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Current assets:
ASSETS
Cash and cash equivalents
Restricted cash
Advances to affiliates
Trade accounts receivable — net
Accounts receivable — affiliates
Notes due from affiliates
Income taxes receivable
Inventories
Commodity and other derivative contractual assets
Margin deposits related to commodity contracts
Prepaid expense and other current assets
Total current assets
Restricted cash
Investments
Investment in unconsolidated subsidiary
Investment in affiliated companies
Operating lease right-of-use assets
Property, plant and equipment — net
Goodwill
Identifiable intangible assets — net
Commodity and other derivative contractual assets
Accumulated deferred income taxes
Other noncurrent assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings
Accounts receivable securitization program
Advances from affiliates
Long-term debt due currently
Trade accounts payable
Accounts payable — affiliates
Notes due to affiliates
Commodity and other derivative contractual
liabilities
Margin deposits related to commodity contracts
Accrued taxes
Accrued taxes other than income
Accrued interest
$
$
$
$
$
199
15
56
705
275
122
—
436
1,326
191
172
3,497
28
1,500
124
697
32
13,402
2,339
2,435
134
398
269
24,855
350
—
—
185
855
—
—
1,505
8
—
188
138
45
89
—
781
—
—
—
33
14
11
27
1,000
—
37
—
—
12
508
214
264
2
—
16
2,053
$
$
— $
450
57
6
211
127
122
31
—
—
12
8
— $
—
(56)
(126)
(275)
(122)
—
—
(7)
—
(1)
(587)
—
—
—
(9,061)
—
—
—
—
—
(61)
—
(9,709) $
— $
—
(57)
(1)
(120)
(272)
(122)
(7)
—
—
—
(6)
300
147
—
1,365
—
—
—
469
1,333
202
298
4,114
28
1,537
124
—
44
13,914
2,553
2,748
136
1,066
352
26,616
350
450
—
277
947
—
—
1,529
8
1
200
151
56
43
—
5
—
—
—
—
—
—
100
204
—
—
—
8,364
—
4
—
49
—
729
67
9,417
$
$
— $
—
—
87
1
145
—
—
—
1
—
11
168
Condensed Consolidating Balance Sheet
as of December 31, 2019
(Millions of Dollars)
Asset retirement obligations
Operating lease liabilities
Other current liabilities
Total current liabilities
Long-term debt, less amounts due currently
Operating lease liabilities
Commodity and other derivative contractual liabilities
Accumulated deferred income taxes
Tax Receivable Agreement obligation
Asset retirement obligations
Other noncurrent liabilities and deferred credits
Total liabilities
Total stockholders' equity
Noncontrolling interest in subsidiary
Total liabilities and equity
$
Parent
(Issuer)
—
—
46
291
689
—
—
—
455
—
22
1,457
7,960
—
9,417
Guarantor
Subsidiaries
141
10
402
3,782
9,385
33
392
—
—
2,084
815
16,491
8,364
—
24,855
$
Non-
Guarantor
Subsidiaries
—
4
58
1,086
28
8
5
63
—
13
153
1,356
696
1
2,053
$
Eliminations
—
—
—
(585)
—
—
(1)
(61)
—
—
(1)
(648)
(9,061)
—
(9,709) $
Consolidated
141
14
506
4,574
10,102
41
396
2
455
2,097
989
18,656
7,959
1
26,616
$
Condensed Consolidating Balance Sheet
as of December 31, 2018
(Millions of Dollars)
Parent
(Issuer)
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
Current assets:
ASSETS
$
Cash and cash equivalents
Restricted cash
Advances to affiliates
Trade accounts receivable — net
Accounts receivable — affiliates
Notes due from affiliates
Income taxes receivable
Inventories
Commodity and other derivative contractual assets
Margin deposits related to commodity contracts
Prepaid expense and other current assets
Total current assets
$
171
57
11
4
—
—
—
—
—
—
2
245
$
453
—
11
729
245
101
1
391
730
361
134
3,156
$
12
—
—
464
—
—
—
21
—
—
16
513
— $
—
(22)
(110)
(245)
(101)
(1)
—
—
—
—
(479)
636
57
—
1,087
—
—
—
412
730
361
152
3,435
169
Condensed Consolidating Balance Sheet
as of December 31, 2018
(Millions of Dollars)
Investments
Investment in unconsolidated subsidiary
Investment in affiliated companies
Property, plant and equipment — net
Goodwill
Identifiable intangible assets — net
Commodity and other derivative contractual assets
Accumulated deferred income taxes
Other noncurrent assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program
Advances from affiliates
Long-term debt due currently
Trade accounts payable
Accounts payable — affiliates
Notes due to affiliates
Commodity and other derivative contractual
liabilities
Margin deposits related to commodity contracts
Accrued taxes
Accrued taxes other than income
Accrued interest
Asset retirement obligations
Other current liabilities
Total current liabilities
Long-term debt, less amounts due currently
Commodity and other derivative contractual liabilities
Accumulated deferred income taxes
Tax Receivable Agreement obligation
Asset retirement obligations
Other noncurrent liabilities and deferred credits
Total liabilities
Total stockholders' equity
Noncontrolling interest in subsidiary
Total liabilities and equity
$
$
$
Parent
(Issuer)
—
—
11,186
15
—
10
—
809
255
12,520
Guarantor
Subsidiaries
1,218
131
263
14,017
2,068
2,480
109
599
330
24,371
$
Non-
Guarantor
Subsidiaries
32
—
—
580
—
3
—
—
5
1,133
$
Eliminations
—
—
(11,449)
—
—
—
—
(72)
—
(12,000) $
Consolidated
1,250
131
—
14,612
2,068
2,493
109
1,336
590
26,024
$
— $
—
23
2
236
—
— $
—
163
928
—
—
—
—
11
—
48
—
74
394
3,819
—
—
420
—
20
4,653
7,867
—
12,520
$
1,376
4
—
181
29
156
267
3,104
7,027
270
—
—
2,203
581
13,185
11,186
—
24,371
$
339
22
5
121
9
101
—
—
—
1
4
—
4
606
28
—
82
—
14
140
870
259
4
1,133
$
$
— $
(22)
—
(106)
(245)
(101)
—
—
(1)
—
(4)
—
—
(479)
—
—
(72)
—
—
—
(551)
(11,449)
—
(12,000) $
339
—
191
945
—
—
1,376
4
10
182
77
156
345
3,625
10,874
270
10
420
2,217
741
18,157
7,863
4
26,024
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
170
Item 9A. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the participation of our management, including the principal
executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and
procedures (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) in effect at December 31, 2019. On
the Ambit Acquisition Date, we completed the Ambit Transaction. Vistra Energy is currently in the process of evaluating the
internal controls of the acquired business and integrating it into our existing operations. As permitted by the SEC, management
has elected to exclude Ambit Holdings, LLC from its assessment of the effectiveness of its internal controls over financial
reporting as of December 31, 2019. Based on the evaluation performed, our principal executive officer and principal financial
officer concluded that the disclosure controls and procedures were effective as of that date.
Other than the changes resulting from the Ambit Transaction, 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 ENERGY CORP.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Vistra Energy Corp. is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Vistra
Energy Corp.'s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.
The management of Vistra Energy Corp. performed an evaluation of the effectiveness of the company's internal control over
financial reporting as of December 31, 2019 based on the Committee of Sponsoring Organizations of the Treadway
Commission’s (COSO's) Internal Control - Integrated Framework (2013). Based on the review performed, management
believes that as of December 31, 2019 Vistra Energy Corp.'s internal control over financial reporting was effective.
On November 1, 2019, an indirect, wholly owned subsidiary of Vistra Energy Corp. acquired Ambit Holdings, LLC, as further
described in Note 2, Acquisitions, Merger Transaction and Business Combination Accounting. Ambit Holdings, LLC's financial
statements comprised approximately 3% of the company's total assets as of December 31, 2019 and approximately 2% and less
than 1%, respectively of the company's total revenues and net income for the year ended December 31, 2019. As of December
31, 2019, we are in the process of evaluating the internal controls of the acquired business and integrating it into our existing
operations. As permitted by the SEC, management has elected to exclude Ambit Holdings, LLC from its assessment of the
effectiveness of its internal control over financial reporting as of December 31, 2019.
The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial
statements of Vistra Energy Corp. has issued an attestation report on Vistra Energy Corp.’s internal control over financial
reporting.
/s/ CURTIS A. MORGAN
Curtis A. Morgan
President and Chief Executive Officer
(Principal Executive Officer)
February 28, 2020
/s/ DAVID A. CAMPBELL
David A. Campbell
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
171
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Vistra Energy Corp.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Vistra Energy Corp. and its subsidiaries (the “Company”) as of
December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal
Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our
report dated February 28, 2020, expressed an unqualified opinion on those financial statements.
As described in Management’s Annual Report on Internal Control over Financial Reporting, management excluded from its
assessment the internal control over financial reporting at Ambit Holdings, LLC, which was acquired on November 1, 2019 and
whose financial statements constitute approximately 3% of total assets, approximately 2% of revenues, and less than 1% of net
income of the consolidated financial statement amounts as of and for the year ended December 31, 2019. Accordingly, our audit
did not include the internal control over financial reporting at Ambit Holdings, LLC.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s
Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s
internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 28, 2020
172
Item 9B. OTHER INFORMATION
None.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Code of Ethics
PART III
Vistra Energy has adopted a code of ethics entitled "Vistra Energy Code of Conduct" that applies to directors, officers and
employees, including the chief executive officer and senior financial officers of Vistra Energy. It may be accessed through the
"Corporate Governance" section of the Company's website at www.vistraenergy.com. Vistra Energy also elects to disclose the
information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the
Code of Ethics," through the Company's website and will disclose such events within four business days following the date of
the amendment or waiver, and such information will remain available on this website for at least a 12-month period. A copy of
the "Vistra Energy Code of Conduct" is available in print to any stockholder who requests it.
Other information required by this Item is incorporated by reference to the similarly named section of Vistra Energy's
Definitive Proxy Statement for its 2020 Annual Meeting of Stockholders.
Item 11. EXECUTIVE COMPENSATION
Information required by this Item is incorporated by reference to the similarly named section of Vistra Energy's Definitive
Proxy Statement for its 2020 Annual Meeting of Stockholders.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Information required by this Item is incorporated by reference to the sections entitled "Beneficial Ownership of Common
Stock of the Company" in Vistra Energy's Definitive Proxy Statement for its 2020 Annual Meeting of Stockholders.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by this Item is incorporated by reference to the sections entitled "Business Relationships and Related
Person Transactions Policy" and "Director Independence" in Vistra Energy's Definitive Proxy Statement for its 2020 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 Energy's Definitive Proxy Statement for its 2020 Annual Meeting of Stockholders.
173
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)
EXHIBITS:
Vistra Energy Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2019
Exhibits
Previously Filed With File
Number*
As
Exhibit
(2)
2.1
2.2
(3(i))
3.1
3.2
Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
333-215288
Form S-1
(filed December 23, 2016)
2.1
— Order of the United States Bankruptcy Court for the District of
Delaware Confirming the Third Amended Joint Plan of
Reorganization
001-38086
Form 8-K
(filed October 31, 2017)
Articles of Incorporation
333-215288
Form S-1
(filed December 23, 2016)
333-215288
Form S-1
(filed December 23, 2016)
2.1
— Agreement and Plan of Merger, dated as of October 29, 2017, by
and between Vistra Energy Corp. and Dynegy, Inc.
3.1
3.2
Certification of Incorporation of TCEH Corp. (now known as
Vistra Energy Corp.), dated October 3, 2016
— Certificate of Amendment of Certificate of Incorporation of TCEH
Corp. (now known as Vistra Energy Corp.), dated November 2,
2016
(3(ii))
By-laws
3.3
(4)
4.1
4.2
4.3
4.4
4.5
4.6
333-215288
Form S-1
(filed December 23, 2016)
3.3
— Restated Bylaws of Vistra Energy Corp., dated November 4, 2016
Instruments Defining the Rights of Security Holders, Including Indentures
001-33443
Form 8-K for Dynegy Inc.
(filed on May 21, 2013)
001-33443
Form 10-K (Year ended
December 31, 2013) (filed
on February 27, 2014)
4.1
— 2023 Notes Indenture, dated May 20, 2013, among Dynegy, the
Subsidiary Guarantors and the Trustee
4.3
— First Supplemental Indenture to the 2023 Notes Indenture, dated as
of December 5, 2014, among Dynegy, the Subsidiary Guarantors
and the Trustee
001-33443
Form 8-K for Dynegy Inc.
(filed on April 7, 2015)
4.20 — Second Supplemental Indenture to the 2023 Notes Indenture, dated
April 1, 2015, among Dynegy, the Subsidiary Guarantors and the
Trustee
001-33443
Form 8-K for Dynegy Inc.
(filed on April 8, 2015)
4.28 — Third Supplemental Indenture to the 2023 Notes Indenture, dated
April 2, 2015, among Dynegy, the Subsidiary Guarantors and the
Trustee
001-33443
Form 10-Q for Dynegy Inc.
(Quarter ended June 30,
2015)
(filed on August 7, 2015)
001-33443
Form 10-Q for Dynegy Inc.
(Quarter ended September
30, 2015) (filed on
November 5, 2015)
4.4
— Fourth Supplemental Indenture to the 2023 Notes Indenture, dated
May 11, 2015, among Dynegy, the Subsidiary Guarantors
4.4
— Fifth Supplemental Indenture to the 2023 Notes Indenture, dated
September 21, 2015, among Dynegy, the Subsidiary Guarantors
and the Trustee
174
Exhibits
4.7
4.8
4.9
4.10
4.11
Previously Filed With File
Number*
001-33443
Form10-K (Year ended
December 31, 2016) (filed
on February 24, 2017)
001-33443
Form10-K (Year ended
December 31, 2016) (filed
on February 24, 2017)
001-38086
Form 8-K
(filed on April 9, 2018)
001-38086
Form 8-K
(filed on June 15, 2018)
001-33443
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.12
**
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
001-33443
Form 8-K for Dynegy Inc.
(filed on May 21, 2013)
001-33443 Form 8-K for
Dynegy Inc.
(filed on October 11, 2016)
001-33443
Form 10-K (Year ended
December 31, 2016) (filed
on February 24, 2017)
001-33443
Form 10-K (Year ended
December 31, 2016) (filed
on February 24, 2017)
001-38086
Form 8-K
(filed on April 9, 2018)
001-38086
Form 8-K
(filed on June 15, 2018)
001-38086
Form 8-K
(filed on August 23, 2018)
001-33443
Form 10-Q for Dynegy Inc.
(Quarter ended September
30, 2019) (filed on
November 5, 2019)
As
Exhibit
4.7
— Sixth Supplemental Indenture to the 2023 Notes Indenture, dated
February 2, 2017, among Dynegy, the Subsidiary Guarantors and
the Trustee
4.8
— Seventh Supplemental Indenture to the 2023 Notes Indenture, dated
February 7, 2017, among Dynegy, the Subsidiary Guarantors and
the Trustee
4.29 — Eighth Supplemental Indenture to the 2023 Notes Indenture, dated
April 9, 2018, among the Company, the Subsidiary Guarantors and
the Trustee
4.2
4.1
— Ninth Supplemental Indenture to the 2023 Notes Indenture, dated
June 14, 2018, among the Guaranteeing Subsidiaries, the Company,
the Subsidiary Guarantors and the Trustee
— Tenth Supplemental Indenture to the 2023 Notes Indenture, dated
August 30, 2019, among the Guaranteeing Subsidiaries,
the
Company, the Subsidiary Guarantors and the Trustee
— Eleventh Supplemental Indenture to the 2023 Notes Indenture,
dated October 25, 2019, among the Guaranteeing Subsidiaries, the
Company, the Subsidiary Guarantors and the Trustee
4.1
— Form of 5.875% Senior Note due 2023
4.1
— 2025 Notes Indenture, dated October 11, 2016, between Dynegy
and the Trustee
4.35 — First Supplemental Indenture to the 2025 Notes Indenture, dated
February 2, 2017, between Dynegy, the Subsidiary Guarantors and
the Trustee
4.36 — Second Supplemental Indenture to the 2025 Notes Indenture, dated
February 7, 2017, between Dynegy, the Subsidiary Guarantors and
the Trustee
4.48 — Third Supplemental Indenture to the 2025 Notes Indenture, dated
April 9, 2018, among the Company, the Subsidiary Guarantors and
the Trustee
4.5
4.6
4.3
— Fourth Supplemental Indenture to the 2025 Notes Indenture, dated
June 14, 2018, among the Guaranteeing Subsidiaries, the Company,
the Subsidiary Guarantors and the Trustee
— Fifth Supplemental Indenture to the 2025 Notes Indenture, dated
August 22, 2018, by and among the Company and Wilmington
Trust, National Association, as Trustee
— Sixth Supplemental Indenture to the 2025 Notes Indenture, dated
August 30, 2019, among the Guaranteeing Subsidiaries,
the
Company, the Subsidiary Guarantors and the Trustee
4.21
**
— Seventh Supplemental Indenture to the 2025 Notes Indenture, dated
October 25, 2019, among the Guaranteeing Subsidiaries,
the
Company, the Subsidiary Guarantors and the Trustee
175
Exhibits
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
Previously Filed With File
Number*
001-33443
Form 8-K
(filed on October 11, 2016)
001-33443
Form 8-K
(filed on August 21, 2017)
001-33443
Form 8-K
(filed on August 21, 2017)
As
Exhibit
4.1
— Form of 8.000% Senior Note due 2025
4.1
— 2026 Notes Indenture, dated August 21, 2017, among Dynegy, the
Subsidiary Guarantors and the Trustee
4.2
— Registration Rights Agreement, dated August 21, 2017, among
Dynegy, the Subsidiary Guarantors and the Trustee
001-38086
Form 8-K
(filed on August 23, 2018)
10.1 — Amendment No. 1 to Registration Rights Agreement dated as of
August 22, 2018, by and among the Company and the Guarantors
(as defined therein)
001-38086
Form 8-K
(filed on April 9, 2018)
001-38086
Form 8-K
(filed on June 15, 2018)
001-38086
Form 8-K
(filed on August 23, 2018)
001-33443
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.30
**
4.31
4.32
4.33
4.34
4.35
001-33443
Form 8-K
(filed on August 21, 2017)
001-38086
Form 8-K
(filed on August 23, 2018)
001-38086
Form 8-K
(filed on August 23, 2018)
001-38086
Form 8-K
(filed on August 23, 2018)
001-33443
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.36
**
4.52 — First Supplemental Indenture to the 2026 Notes Indenture, dated
April 9, 2018, among the Company, the Subsidiary Guarantors and
the Trustee
4.6
4.4
4.4
— Second Supplemental Indenture to the 2026 Notes Indenture, dated
June 14, 2018, among the Guaranteeing Subsidiaries, the Company,
the Subsidiary Guarantors and the Trustee
— Third Supplemental Indenture to the 2026 Notes Indenture, dated
August 22, 2018, by and among the Company and Wilmington
Trust, National Association, as Trustee
— Fourth Supplemental Indenture to the 2026 Notes Indenture, dated
August 30, 2019, among the Guaranteeing Subsidiaries,
the
Company, the Subsidiary Guarantors and the Trustee
— Fifth Supplemental Indenture to the 2026 Notes Indenture, dated
October 25, 2019, among the Guaranteeing Subsidiaries,
the
Company, the Subsidiary Guarantors and the Trustee
4.1
— Form of 8.125% Senior Note due 2026
4.1
— Indenture for 5.500% Senior Note due 2026, dated as of August 22,
the
2018, among Vistra Operations Company LLC, as issuer,
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee
4.2
— Form of Rule 144A Global Security for 5.500% Senior Note due
2026 (included in Exhibit 4.1)
4.3
— Form of Regulation S Global Security for 5.500% Senior Note due
2026 (included in Exhibit 4.1)
4.5
— First Supplemental Indenture for the 5.500% Senior Notes due
2019,
the Guaranteeing
the Subsidiary Guarantors and the
30,
the Company,
dated August
among
2026,
Subsidiaries,
Trustee
— Second Supplemental Indenture for the 5.500% Senior Notes due
among the Guaranteeing
the Subsidiary Guarantors and the
2026, dated October 25, 2019,
Subsidiaries,
Trustee
the Company,
4.37
001-38086
Form 8-K
(filed on February 6, 2019)
4.1
— Indenture 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
176
Exhibits
4.38
4.39
4.40
Previously Filed With File
Number*
001-38086
Form 8-K
(filed on February 6, 2019)
001-38086
Form 8-K
(filed on February 6, 2019)
001-33443
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.41
**
4.42
4.43
4.44
4.45
001-38086
Form 8-K
(filed on June 24, 2019)
001-38086
Form 8-K
(filed on June 24, 2019)
001-38086
Form 8-K
(filed on June 24, 2019)
001-33443
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.46
**
4.47
4.48
4.49
4.50
4.51
4.52
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)
As
Exhibit
4.2
— Form of Rule 144A Global Security for 5.625% Senior Note
due2027 (included in Exhibit 4.1)
4.3
— Form of Regulation S Global Security for 5.625% Senior Note due
2027 (included in Exhibit 4.1)
4.6
4.1
— First Supplemental Indenture for the 5.625% Senior Notes due
2019,
the Guaranteeing
the Subsidiary Guarantors and the
30,
the Company,
dated August
among
2027,
Subsidiaries,
Trustee
— Second Supplemental Indenture for the 5.625% Senior Notes due
among the Guaranteeing
the Subsidiary Guarantors and the
2027, dated October 25, 2019,
Subsidiaries,
Trustee
the Company,
— Indenture for 5.00% Senior Notes due 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
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
4.1
4.2
— First Supplemental Indenture for the 5.000% Senior Notes due
the Guaranteeing
2019,
the Subsidiary Guarantors and the
30,
the Company,
dated August
among
2027,
Subsidiaries,
Trustee
— Second Supplemental Indenture for the 5.000% Senior Notes due
among the Guaranteeing
the Subsidiary Guarantors and the
2027, dated October 25, 2019,
Subsidiaries,
Trustee
the Company,
— Indenture, dated as of June 11, 2019, between Vistra Operations
Company LLC, as Issuer, the and Wilmington Trust, National
Association, as Trustee
— Supplemental Indenture for 3.55% Senior Secured Notes due 2024
and 4.30% Senior Secured Notes Due 2029, dated as of June 11,
the
2019, among Vistra Operations Company LLC, as Issuer,
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)
177
Exhibits
4.53
Previously Filed With File
Number*
001-33443
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
As
Exhibit
4.8
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63
4.64
001-38086
Form 8-K (filed
on November 21, 2019)
001-38086
Form 8-K (filed
on November 21, 2019)
001-38086
Form 8-K (filed
on November 21, 2019)
001-38086
Form 8-K (filed
on November 21, 2019)
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)
001-38086
Form 8-K
(filed on April 5, 2019)
— Second Supplemental Indenture for 3.55% Senior Secured Notes
due 2024 and 4.30% Senior Secured Notes due 2029, dated as of
August 30, 2019, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors
and the Trustee
— Third Supplemental Indenture for 3.55% Senior Secured Notes due
2024 and 4.30% Senior Secured Notes due 2029, dated as of
October 25, 2019, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, Subsidiary Guarantors and
the Trustee
— 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
4.1
4.2
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)
4.7
4.8
4.1
4.2
— Purchase and Sale Agreement dated as of August 21, 2018,
between TXU Energy Retail Company LLC as originator, and TXU
Energy Receivables Company LLC, as purchaser
— Receivable Purchase Agreement dated as of August 21, 2018,
among TXU Energy Receivables Company LLC, as seller, TXU
Energy Retail Company LLC, as servicer, Vistra Operations
Company LLC, as performance guarantor, certain purchaser agents
and purchasers named therein and Credit Agricole Corporate and
Investment Bank, as administrator
— 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 Receivables Company
LLC, as purchaser
— First Amendment to Receivables Purchase Agreement, dated as of
April 1, 2019, among TXU Energy Receivables Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
001-33443
Form 10-Q (Quarter ended
June 30, 2019) (filed on
August 2, 2019)
001-33443
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 Receivables Company
LLC, as purchaser
4.13 — Second Amendment to Receivables Purchase Agreement, dated as
of June 3, 2019, among TXU Energy Receivables Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
001-38086
Form 8-K
(filed on July 19, 2019)
4.1
— 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,
each as an originator, and TXU Energy Receivables Company
LLC, as purchaser
178
Exhibits
4.65
Previously Filed With File
Number*
001-38086
Form 8-K
(filed on July 19, 2019)
As
Exhibit
4.2
— Third Amendment to Receivables Purchase Agreement, dated as of
July 15, 2019, among TXU Energy Receivables Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.66
4.67
4.68
4.69
4.70
(10)
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
001-33443
Form of 8-K
(filed on February 7, 2017)
4.1
— Warrant Agreement, dated February 2, 2017, by and among
Dynegy, Computershare Inc. and Computershare Trust Company,
N.A., as warrant agent
001-38086
Registration Statement on
Form 8-A
(filed on April 9, 2018)
001-33443
Form of 8-K
(filed on February 7, 2017)
333-215288
Form S-1
(filed December 23, 2016)
**
Material Contracts
4.2
— Supplemental Warrant Agreement, dated as of April 9, 2018 among
the Company and the Warrant Agent
4.1
— Form of Warrant
4.1
— Registration Rights Agreement, by and among TCEH Corp. (now
known as Vistra Energy Corp.) and the Holders party thereto, dated
as of October 3, 2016
— Description of Capital Stock
Management Contracts; Compensatory Plans, Contracts and Arrangements
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
001-33443
Form10-K (Year ended
December 31, 2017) (filed
on February 26, 2018)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
001-33443
Form10-K (Year ended
December 31, 2018) (filed
on February 28, 2019)
001-38086
Form 8-K
(filed on May 23, 2019)
001-33443
Form10-K (Year ended
December 31, 2018) (filed
on February 28, 2019)
10.6 — 2016 Omnibus Incentive Plan
10.7 — Form of Option Award Agreement
Omnibus Incentive Plan
(Management)
for 2016
10.8 — Form of Restricted Stock Unit Award Agreement (Management)
for 2016 Omnibus Incentive Plan
10(d) — Form of Performance Stock Unit Award Agreement for 2016
Omnibus Incentive Plan
10.9 — Vistra Energy Corp. Executive Annual Incentive Plan
10.6 — Amended and Restated 2016 Omnibus Incentive Plan, effective as
of February 26, 2019
10.1 — Amended and Restated 2016 Omnibus Incentive Plan, effective as
of May 20, 2019
10.7 — Vistra Energy Equity Deferred Compensation Plan for Certain
Directors
179
Exhibits
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
Previously Filed With File
Number*
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
001-38086
Form 8-K
(filed May 4, 2018)
001-33443
Form 10-Q (Quarter ended
March 31, 2019) (filed on
May 3, 2019)
001-38086
Form 8-K
(filed May 28, 2019)
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
Form 10-K (Year ended
December 31, 2018) (filed
on February 25, 2019)
001-33443
Form 10-K (Year ended
December 31, 2018) (filed
on February 25, 2019)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
As
Exhibit
10.10 — Stockholder's Agreement, dated as of October 3, 2016, by and
between TCEH Corp. (now known as Vistra Energy Corp.) and
Apollo Management Holdings, L.P.
10.19 — Employment Agreement between Curtis A. Morgan and Vistra
Energy Corp.
10.1 — Amended and Restated Employment Agreement, dated as of May
1,2018, between Curtis A. Morgan and Vistra Energy Corp.
10.5 — Amended and Restated Employment Agreement, dated May 1,
2019, between James A. Burke and Vistra Energy Corp.
10.1 — Employment Agreement, dated May 28, 2019, by and between
David Campbell and Vistra Energy Corp.
10.22 — Employment Agreement between Stephanie Zapata Moore and
Vistra Energy Corp.
10.23 — Employment Agreement between Carrie Lee Kirby and Vistra
Energy Corp.
10.18 — Agreement between Scott A. Hudson, Vistra Energy Corp. and
TXU Retail Service Company
10.19 — Agreement between Stephen J. Muscato, Vistra Energy Corp. and
Luminant Energy Company LLC
10.26 — Form of indemnification agreement with directors
10.29 — Stock Purchase Agreement, dated as of October 25, 2016, by and
between TCEH Corp. (now known as Vistra Energy Corp.) and
Curtis A. Morgan
Credit Agreements and Related Agreements
333-215288
Form S-1
(filed December 23, 2016)
333-215288
Form S-1
(filed December 23, 2016)
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.
180
Exhibits
10.22
10.23
10.24
10.25
10.26
10.27
Previously Filed With File
Number*
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)
001-38086
Form 8-K
(filed February 22, 2018)
001-38086
Form 8-K
(filed June 15, 2018)
10.28
001-38086
Form 8-K
(filed April 4, 2019)
10.29
001-38086
Form 8-K
(filed May 29, 2019)
10.30
001-38086
Form 8-K (filed
on November 21, 2019)
As
Exhibit
10.3 — Second Amendment to Credit Agreement, dated February 1, 2017,
by and among Deutsche Bank AG New York Branch, Vistra
Operations Company LLC, Vistra Intermediate Company LLC and
the other Credit Parties and Lenders party thereto.
10.4 — Third Amendment to Credit Agreement, dated February 28, 2017,
by and among Deutsche Bank AG New York Branch, Vistra
Operations Company LLC, Vistra Intermediate Company LLC and
the other Credit Parties and Lenders party thereto.
10.1 — Fourth Amendment to Credit Agreement, dated as of August 17,
2017 (effective August 17, 2017), by and among Deutsche Bank
AG New York Branch, Vistra Operations Company LLC, Vistra
Intermediate Company LLC and the other Credit Parties and
Lenders party thereto.
10.1 — Fifth Amendment to Credit Agreement, dated as of December 14,
2017 (effective December 14, 2017), by and among Deutsche Bank
AG New York Branch, Vistra Operations Company LLC, Vistra
Intermediate Company LLC and the other Credit Parties and
Lenders party thereto.
10.1 — Sixth Amendment to Credit Agreement, dated as of February 20,
2018 (effective February 20, 2018), by and among Deutsche Bank
AG New York Branch, Vistra Operations Company LLC, Vistra
Intermediate Company LLC and the other Credit Parties and
Lenders party thereto.
10.1 — Seventh Amendment to Credit Agreement, dated as of June 14,
2018, by and among Vistra Operations Company LLC, Vistra
Intermediate Company LLC, the other Credit Parties party thereto,
Credit Suisse and Citibank, N.A. as the 2018 Incremental Term
Loan Lenders,
the various other Lenders party thereto, Credit
Suisse as Successor Administrative Agent and as Successor
Collateral Agent, and Delaware Trust Company, as Collateral
Trustee.
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
thereto,
(as defined in the Credit
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
10.31
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
181
Exhibits
10.32
Previously Filed With File
Number*
001-38086
Form 8-K
(filed on January 24, 2019)
As
Exhibit
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
10.33
10.34
10.35
10.36
10.37
10.38
10.39
10.40
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)
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)
10.41
001-38086
Form 8-K
(filed on June 15, 2018)
10.42
001-38086
Form 8-K
(filed on June 15, 2018)
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
10.10 — Assumption Agreement, dated as of April 9, 2018, between Vistra
Energy Corp. (as successor by merger to Dynegy Inc.), and Credit
Suisse AG, Cayman Islands Branch, as Administrative Agent and
as Collateral Trustee.
10.11 — Guarantee and Collateral Agreement, dated as of April 23, 2013,
among Dynegy Inc., the subsidiaries of the borrower from time to
time party thereto and Credit Suisse AG, Cayman Islands Branch,
as Collateral Trustee (incorporated by reference to Exhibit 10.2 to
the Current Report on Form 8-K of Dynegy Inc. filed on April 24,
2013).
10.12 — Joinder, dated as of April 9, 2018, among Vistra Energy Corp., the
subsidiary guarantors party thereto and Credit Suisse AG, Cayman
Islands Branch, as Collateral Trustee.
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 from time to time (incorporated by reference to
Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc.
filed on April 24, 2013).
10.5 — Collateral Trust Agreement, dated as of October 3, 2016, by and
among TEX Operations Company LLC (now known as Vistra
Operations LLC), the Grantors from time to time thereto, Railroad
Commission of Texas, as first-out representative, and Deutsche
Bank AG, New York Branch, as
senior credit agreement
representative
10.2 — Amendment to Collateral Trust Agreement, effective as of June 14,
2018, among Vistra Operations Company LLC, the other Grantors
from time to time party thereto, Railroad Commission of Texas, as
first-out representative, and Credit Suisse AG, Cayman Islands
Branch, as senior credit agreement agent, and Delaware Trust
Company, as Collateral Trustee
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.
182
Exhibits
10.43
10.44
10.45
10.46
10.47
10.48
10.49
10.50
10.51
(21)
21.1
(23)
23.1
(31)
31.1
31.2
Previously Filed With File
Number*
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
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)
As
Exhibit
10.13 — Tax Receivable Agreement, by and between TEX Energy LLC
(now known as Vistra Energy Corp.) and American Stock Transfer
& Trust Company, as transfer agent, dated as of October 3, 2016
10.14 — Tax Matters Agreement, by and among TEX Energy LLC (now
known as Vistra Energy Corp.), EFH Corp., Energy Future
Intermediate Holding Company LLC, EFI Finance Inc. and EFH
Merger Co. LLC, dated as of October 3, 2016
10.15 — Transition Services Agreement, by and between Energy Future
Holdings Corp. and TEX Operations Company LLC (now known
as Vistra Operations Company LLC), dated as of October 3, 2016
10.16 — Separation Agreement, by and between Energy Future Holdings
Corp., TEX Energy LLC (now known as Vistra Energy Corp.) and
TEX Operations Company LLC (now known as Vistra Operations
LLC), dated as of October 3, 2016
10.17 — Purchase and Sale Agreement, dated as of November 25, 2015, by
and between La Frontera Ventures, LLC and Luminant Holding
Company LLC
10.18 — Amended and Restated Split Participant Agreement, by and
between Oncor Electric Delivery Company LLC (f/k/a TXU
Electric Delivery Company) and TEX Operations Company LLC
(now known as Vistra Operations Company LLC), dated as of
October 3, 2016
10.27 — Lease Agreement, dated February 14, 2002, between State Street
Bank and Trust Company of Connecticut, National Association, an
owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust,
as lessor and EFH Properties Company (now known as Vistra EP
Properties Company), as Lessee (Energy Plaza Property)
10.28 — First Amendment, dated June 1, 2007, to Lease Agreement, dated
February 14, 2002
10(a) — Asset Purchase Agreement, dated as of July 5, 2017, by and among
Odessa-Ector Power Partners, L.P., La Frontera Holdings, LLC,
Vistra Operations Company LLC, Koch Resources, LLC
Subsidiaries of the Registrant
**
Consent of Experts
**
— Significant Subsidiaries of Vistra Energy Corp.
— Consent of Deloitte & Touche LLP
Rule 13a-14(a) / 15d-14(a) Certifications
**
**
— Certification of Curtis A. Morgan, principal executive officer of
Vistra Energy Corp., pursuant to Section 302 of the Sarbanes-
Oxley Act of 2002
— Certification of David A. Campbell, principal financial officer of
Vistra Energy Corp., pursuant to Section 302 of the Sarbanes-
Oxley Act of 2002
(32)
Section 1350 Certifications
183
Exhibits
Previously Filed With File
Number*
As
Exhibit
32.1
***
32.2
***
(95)
95.1
Mine Safety Disclosures
**
XBRL Data Files
101.INS
**
101.SCH **
101.CAL **
101.DEF
**
101.LAB **
101.PRE
**
104
____________________
*
**
***
Incorporated herein by reference
Filed herewith
Furnished herewith
Item 16. FORM 10-K SUMMARY
None.
— Certification of Curtis A. Morgan, principal executive officer of
Vistra Energy Corp., pursuant to U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
— Certification of David A. Campbell, principal financial officer of
Vistra Energy Corp., pursuant to U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
— Mine Safety Disclosures
— The following financial information from Vistra Energy Corp.'s
Annual Report on Form 10-K for the year ended December 31,
2019 formatted in Inline XBRL (Extensible Business Reporting
Language) includes: (i) the Consolidated Statements of Operations,
(ii) the Consolidated Statements of Comprehensive Income (Loss),
(iii)
the
Consolidated Statements of Cash Flows,
Consolidated Balance Sheets, (v) the Consolidated Statement of
Changes in Equity (vi) the Notes to the Consolidated Financial
Statements.
(iv)
the
— XBRL Taxonomy Extension Schema Document
— XBRL Taxonomy Extension Calculation Linkbase Document
— XBRL Taxonomy Extension Definition Linkbase Document
— XBRL Taxonomy Extension Label Linkbase Document
— XBRL Taxonomy Extension Presentation Linkbase Document
— Cover Page Interactive Data File (formatted as Inline XBRL and
contained in Exhibit 101).
184
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Vistra Energy Corp. has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 28, 2020
VISTRA ENERGY CORP.
By
/s/ CURTIS A. MORGAN
Curtis A. Morgan (President and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of Vistra Energy Corp. and in the capacities and on the date indicated.
Signature
Title
Date
/s/ CURTIS A. MORGAN
(Curtis A. Morgan, President and Chief Executive Officer)
Principal Executive Officer
and Director
February 28, 2020
/s/ DAVID A. CAMPBELL
(David A. Campbell, Executive Vice President and Chief Financial
Officer)
Principal Financial Officer
February 28, 2020
/s/ CHRISTY DOBRY
(Christy Dobry, Vice President and Controller)
/s/ SCOTT B. HELM
(Scott B. Helm, Chairman of the Board)
/s/ HILARY E. ACKERMANN
(Hilary E. Ackermann)
/s/ ARCILIA C. ACOSTA
(Arcilia C. Acosta)
/s/ GAVIN R. BAIERA
(Gavin R. Baiera)
/s/ PAUL M. BARBAS
(Paul M. Barbas)
/s/ LISA M. CRUTCHFIELD
(Lisa M. Crutchfield)
/s/ BRIAN K. FERRAIOLI
(Brian K. Ferraioli)
/s/ JEFF D. HUNTER
(Jeff D. Hunter)
(Geoffrey D. Strong)
/s/ JOHN R. SULT
(John R. Sult)
(Bruce Zimmerman)
Principal Accounting Officer
February 28, 2020
Chairman of the Board and
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
Director
February 28, 2020
185
[THIS PAGE INTENTIONALLY LEFT BLANK]
STOCKHOLDER INFORMATION
Stock Exchange Listing
NYSE: VST
Corporate Headquarters
Vistra Energy Corp.
6555 Sierra Drive
Irving, Texas 75039
Stock Transfer Agent and Registrar
Please direct general questions about stockholder accounts,
(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:70)(cid:72)(cid:85)(cid:87)(cid:76)(cid:403)(cid:70)(cid:68)(cid:87)(cid:72)(cid:86)(cid:15)(cid:3)(cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:73)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:15)(cid:3)(cid:82)(cid:85)(cid:3)(cid:71)(cid:88)(cid:83)(cid:79)(cid:76)(cid:70)(cid:68)(cid:87)(cid:72)(cid:3)(cid:80)(cid:68)(cid:76)(cid:79)(cid:76)(cid:81)(cid:74)(cid:86)(cid:3)(cid:87)(cid:82)
Vistra Energy’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)*
(cid:47)(cid:76)(cid:86)(cid:68)(cid:3)(cid:38)(cid:85)(cid:88)(cid:87)(cid:70)(cid:75)(cid:403)(cid:72)(cid:79)(cid:71) (3,4)
Brian K. Ferraioli (1)*
Scott B. Helm, Chairman of the Board of Directors
Jeff D. Hunter (1,4)
Curtis A. Morgan
Geoffrey D. Strong (3)
John R. Sult (1,2)
Bruce E. Zimmerman (1)
Independent Registered Accounting Firm
Deloitte & Touche LLP
(cid:50)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85)(cid:3)(cid:38)(cid:72)(cid:85)(cid:87)(cid:76)(cid:403)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)
(cid:50)(cid:88)(cid:85)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:41)(cid:82)(cid:85)(cid:80)(cid:3)(cid:20)(cid:19)(cid:16)(cid:46)(cid:3)(cid:403)(cid:79)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:40)(cid:38)
1 Audit Committee
2 Compensation Committee
3 Nominating and Governance Committee
4 Sustainability and Risk Committee
is included herein, excluding all exhibits other than our
* Committee Chair
(cid:54)(cid:68)(cid:85)(cid:69)(cid:68)(cid:81)(cid:72)(cid:86)(cid:16)(cid:50)(cid:91)(cid:79)(cid:72)(cid:92)(cid:3)(cid:36)(cid:38)(cid:55)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:22)(cid:19)(cid:21)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:28)(cid:19)(cid:25)(cid:3)(cid:70)(cid:72)(cid:85)(cid:87)(cid:76)(cid:403)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)
by the CEO and CFO. We will send stockholders copies
† As of March 30, 2020. Geoffrey D. Strong and Bruce E. Zimmerman
of the exhibits to our Annual Report on Form 10-K and
will serve on the Board of Directors and their respective
any of our corporate governance documents, free of
committees until April 29, 2020. Besides Curtis A. Morgan, all
charge, upon request.
Note that these documents, along with further information
about our company, board of directors, management
team and contact details, are available on our website at
www.vistraenergy.com.
members of the Vistra Energy Board of Directors satisfy the
independence requirements of the Securities and Exchange
Commission and the NYSE.
Vistra Energy Corp. | 6555 Sierra Drive, Irving, Texas 75039 | www.vistraenergy.com