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VISTRA CORP.

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VISTRA CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

11/04/2022 | 09:29am EST
The discussion below, as well as other portions of this quarterly report on Form
10-Q, contain forward-looking statements within the meaning of Section 27A of
the Securities Act, Section 21E of the Exchange Act and the Private Securities
Litigation Reform Act of 1995. In addition, management may make forward-looking
statements orally or in other writing, including, but not limited to, in press
releases, quarterly earnings calls, executive presentations, in the annual
report to stockholders and in other filings with the SEC. Readers can usually
identify these forward-looking statements by the use of such words as "may,"
"will," "should," "likely," "plans," "projects," "expects," "anticipates,"
"believes" or similar words. These statements involve a number of risks and
uncertainties. Actual results could materially differ from those anticipated by
such forward-looking statements. For more discussion about risk factors that
could cause or contribute to such differences, see Part II, Item 7 "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
Part I, Item 1A "Risk Factors" in the Company's 2021 Form 10-K and any updates
contained herein. Forward-looking statements reflect the information only as of
the date on which they are made. The Company does not undertake any obligation
to update any forward-looking statements to reflect future events, developments,
or other information. If Vistra does update one or more forward-looking
statements, no inference should be drawn that additional updates will be made
regarding that statement or any other forward-looking statements. This
discussion is intended to clarify and focus on our results of operations,
certain changes in our financial position, liquidity, capital structure and
business developments for the periods covered by the condensed consolidated
financial statements included under Part I, Item 1 of this quarterly report on
Form 10-Q for the three and nine months ended September 30, 2022. This
discussion should be read in conjunction with those condensed consolidated
financial statements and the related notes and is qualified by reference to
them.

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2022 and 2021 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements.

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

Critical Accounting Policies and Estimates


The Company's discussion and analysis of its financial position and results of
operations is based upon its condensed consolidated financial statements. The
preparation of these condensed consolidated financial statements requires
estimation and judgment that affect the reported amounts of revenue, expenses,
assets and liabilities. The Company bases its estimates on historical experience
and on various other factors that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments about
the accounting for assets and liabilities that are not readily apparent from
other sources. If the estimates differ materially from actual results, the
impact on the condensed consolidated financial statements may be material. The
Company's critical accounting policies are disclosed in our 2021 Form 10-K.

Business


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

Operating Segments


Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv)
West, (v) Sunset and (vi) Asset Closure. See Note 16 to the Financial Statements
for further information concerning our reportable business segments.

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CEO Transition

In March 2022, Vistra announced that the Board had named Jim Burke as its next
Chief Executive Officer (CEO), effective August 1, 2022. Mr. Burke, who
previously served as President and Chief Financial Officer, also joined the
Company's Board upon assuming his new role. Vistra's previous CEO and director,
Curt Morgan, will serve as a special advisor to Mr. Burke and the Board until
April 30, 2023. The transition from Mr. Morgan to Mr. Burke was a product of the
Company's formal succession planning process. In July 2022, the Company
announced the appointment of Kris Moldovan as the Company's Executive Vice
President and Chief Financial Officer, effective August 1, 2022.

Significant Activities and Events and Items Influencing Future Performance

Climate Change, Investments in Clean Energy and CO2 Reductions


Environmental Regulations - We are subject to extensive environmental regulation
by governmental authorities, including the EPA and the environmental regulatory
bodies of states in which we operate. Environmental regulations could have a
material impact on our business, such as certain corrective action measures that
may be required under the CCR rule and the ELG rule (see Note 11 to the
Financial Statements). However, such rules and the regulatory environment are
continuing to evolve and change, and we cannot predict the ultimate effect that
such changes may have on our business.

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

Solar Generation and Energy Storage Projects - In January 2022, we announced
that, subject to approval by the CPUC, we would enter into a 15-year resource
adequacy contract with PG&E to develop an additional 350 MW battery ESS at our
Moss Landing Power Plant site. The CPUC approved the resource adequacy contract
in April 2022. In September 2021, we announced the planned development, at a
cost of approximately $550 million, of up to 300 MW of solar photovoltaic power
generation facilities and up to 150 MW of battery ESS at retired or
to-be-retired plant sites in Illinois, based on the passage of Illinois Senate
Bill 2408, the Energy Transition Act. In September 2020, we announced the
planned development, at a cost of approximately $850 million, of up to 768 MW of
solar photovoltaic power generation facilities and 260 MW of battery ESS in
Texas. Of this planned development in Texas, 158 MW of solar generation and the
260 MW battery ESS came online in the first nine months of 2022. We will only
invest in these growth projects if we are confident in the expected returns. See
Note 2 to the Financial Statements for a summary of our solar and battery energy
storage projects.

CO2 Reductions - In June 2022 and September 2022, we retired the Zimmer coal
generation facility and the Joppa generation facilities, respectively. See Note
3 to the Financial Statements for a summary of our planned generation
retirements.

Inflation Reduction Act of 2022


In August 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA),
which, among other things, implements substantial new and modified energy tax
credits, including a nuclear production tax credit (PTC), a solar PTC, a
first-time stand-alone battery storage investment tax credit, a 15% alternative
minimum tax on book income of certain large corporations, and a 1% excise tax on
net stock repurchases. Treasury regulations are expected to define the scope of
the legislation in many important respects over the next twelve months. The
corporate alternative minimum tax is not applicable in our next fiscal year
since it is based on a three-year average annual adjusted financial statement
income in excess of $1 billion. The excise tax is not expected to have a
material impact on our financial statements. We have taken the corporate
alternative minimum tax and relevant extensions or expansions of existing tax
credits applicable to projects in our immediate development pipeline into
account when forecasting cash taxes for periods after the law takes effect and
for estimating the TRA liability.

Comanche Peak Nuclear Plant License Renewal


In October 2022, we announced the submission of our application to the NRC for
license renewal at our two-unit Comanche Peak Nuclear Plant. The current
licenses for Units 1 and 2 extend into 2030 and 2033, respectively, and we are
applying to renew the licenses into 2050 and 2053, respectively.

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Moss Landing Outages

In September 2021, Moss Landing Phase I experienced an incident impacting a
portion of the battery ESS. A review found the root cause originated in systems
separate from the battery system. The facility was offline as we performed the
work necessary to return the facility to service. Restoration work on the
facility was completed in June 2022. Moss Landing Phases II and III were not
affected by this incident.

In February 2022, Moss Landing Phase II experienced an incident impacting a
portion of the Battery ESS. A review found the root cause originated in systems
separate from the battery system. The facility was offline as we performed the
work necessary to return the facility to service. Restoration work on the
facility was completed in September 2022. Moss Landing Phases I and III were not
affected by this incident.

These incidents did not have a material impact on our results of operations.

Winter Storm Uri

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows.


The weather event resulted in a $2.9 billion negative impact on the Company's
pre-tax earnings in the nine months ended September 30, 2021. The weather event
resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in
the year ended December 31, 2021, after taking into account approximately $544
million in securitization proceeds Vistra received from ERCOT as further
described below. The primary drivers of the loss were the need to procure power
in ERCOT at market prices at or near the price cap due to lower output from our
natural gas-fueled power plants driven by natural gas deliverability issues and
our coal-fueled power plants driven by coal fuel handling challenges, high fuel
costs, and high retail load costs.

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

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

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 12 to the Financial
Statements for more information about our dividend program.

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Preferred Stock Offerings

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

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

See Note 12 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B Preferred Stock.

Share Repurchase Program


In October 2021, we announced that the Board had authorized a share repurchase
program (Share Repurchase Program) under which up to $2.0 billion of our
outstanding common stock may be repurchased. The Share Repurchase Program became
effective in October 2021. The Share Repurchase Program superseded the $1.5
billion share repurchase program previously announced in September 2020 (2020
Share Repurchase Program). On August 4, 2022, the Board authorized an
incremental $1.25 billion for repurchases under the Share Repurchase Program. We
expect to complete repurchases under the current $3.25 billion Share Repurchase
Program by the end of 2023.

In the nine months ended September 30, 2022, 63,459,123 shares of our common
stock were repurchased under the Share Repurchase Program for approximately
$1.493 billion at an average price of $23.52 per share of common stock (shares
repurchased include 850,349 of unsettled shares repurchased for $18 million as
of September 30, 2022). As of September 30, 2022, approximately $1.348 billion
of the total authorized of $3.25 billion was available for additional
repurchases under the Share Repurchase Program.

From October 1, 2022 through November 1, 2022, 7,076,619 of our common stock had been repurchased under the Share Repurchase Program for $156 million at an average price per share of common stock of $22.04, and at November 1, 2022, $1.192 billion of the total authorized of $3.25 billion was available for repurchase under the Share Repurchase Program.


Since the Share Repurchase Program became effective in October 2021, 89,866,107
shares of our common stock were repurchased for approximately $2.058 billion at
an average price of $22.90 per share of common stock.

See Note 12 to the Financial Statements for more information concerning the Share Repurchase Program.

Macroeconomic Conditions


Global market demand, geopolitical events and high natural gas price volatility
have resulted in increased market prices for energy, and we expect these
conditions to persist, in particular in the near term. Due in large part to the
Russia and Ukraine conflict as well as other factors, we have experienced
substantial shifts in commodity prices, which in turn have (i) facilitated our
comprehensive hedging strategy which we believe has positioned us to lock in
significant revenues and Adjusted EBITDA opportunities in 2023 and beyond, (ii)
led to significant mark-to-market impacts on forward commodity derivative
instruments, and (iii) combined with our comprehensive hedging strategy,
resulted in significant increases in our collateral posting obligations and
required liquidity to support these net liabilities. Additionally, we continue
to monitor domestic drivers of gas prices, including the pace of investment and
buildout of liquefied natural gas (LNG) export capabilities, which have the
potential to more closely align U.S. natural gas pricing with the further
elevated international gas markets over the next couple of years. See also
Financial Condition for further discussion of our collateral posting obligations
and liquidity management activities.

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We continue to monitor the impacts of energy volatility on the retail and
associated default service markets as well. As electricity pricing has trended
higher, we have observed increased customer migration to the default service
provider in territories outside of Texas, where default service rates do not yet
fully reflect the higher commodity pricing environment. Generators (including
Vistra) with contracts to serve a percentage of the resultingly higher than
planned default service load (previously awarded through the default service
auction process) are likely to incur losses on these particular default service
contracts, as the underlying cost to provide the incremental power may have
subsequently risen above the contracted revenue rate. We anticipate these losses
could have a negative impact on our East segment through the end of these
default service contracts in mid-2023.

Accordingly, with forward power and natural gas curves increasing materially in
2022, we have increased our hedging for future periods. As of September 30,
2022, we have hedged approximately 70% of our expected generation volumes on
average for the three-year period 2023 to 2025 (with approximately 90% hedged
for 2023).

Changes to the geopolitical situation and the inflationary environment, among
other factors, have also created supply chain constraints that have reduced the
availability and increased the costs of certain fuels, such as coal, as well as
reduced the availability of certain equipment and supply relevant to
construction of renewables projects. For example, we are closely monitoring the
status of the tentative agreement between labor unions and railroad companies,
which remains subject to ratification by the labor unions. While any failure to
ratify such agreement would not present immediate risk of service disruption,
any future rail strike could require us to hold additional coal inventory, which
could have significant financial costs and limit our ability to operate our
coal-fueled power plants at expected levels. Further, we are proactively
managing through increased costs of materials and supply chain disruptions and
continuing to prudently re-evaluate the business cases and timing of our planned
development projects, which has resulted in a deferral of some of our planned
capital spend for our renewables projects from 2022 to 2023 and beyond. In
addition, our Vistra Zero operational and development projects are anticipated
to benefit from the impact of the recently passed IRA. The inflationary
environment has also led to and is expected to cause further increases in
interest rates, resulting in increased refinancing or borrowing costs, including
project financing for our development projects.

Additionally, we are closely monitoring developments of the Russia and Ukraine
conflict including sanctions (or potential sanctions) against Russian energy
exports and Russian nuclear fuel supply and enrichment activities, as well as
actions by Russia to limit energy deliveries, which may further impact commodity
prices in Europe and globally. Our 2022 refueling has not been affected by the
Russia and Ukraine conflict. We work with a diverse set of global nuclear fuel
cycle suppliers to procure our nuclear fuel, and therefore, we expect to have
enough nuclear fuel to support all our refueling needs for the next few years.
We are taking affirmative action by including mitigating strategies in our
procurement portfolio to ensure we can secure the nuclear fuel needed to
continue to operate our nuclear facility. If imports from Russia were
restricted, U.S. merchant nuclear power generators could be challenged in their
refueling operations in future years.

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. While the financial
impacts resulting from Winter Storm Uri and higher margining requirements as a
result of increasing power prices have caused an increase in our consolidated
net leverage, the Company remains committed to a strong balance sheet. See Note
10 to the Financial Statements for details of our debt activity and Note 9 to
the Financial Statements for details of our accounts receivable financing.

Vistra Operations Credit Agreement Amendments - In April 2022 and July 2022, the
Vistra Operations Credit Agreement was amended to, among other things, (i)
establish new classes of extended revolving credit commitments maturing in April
2027 in aggregate amounts of $2.8 billion and $725 million as of April 2022 and
July 2022, respectively, (ii) require Vistra Operations to terminate at least
$350 million in revolving commitments maturing April 29, 2027 by December 30,
2022 or earlier if Vistra Operations or any guarantor receives proceeds from any
capital markets transaction whose primary purpose is designed to enhance the
liquidity of Vistra Operations and its guarantors, and (iii) appoint certain
additional revolving letter of credit issuers. See Note 10 to the Financial
Statements for details of the Vistra Operations Credit Agreement amendments.

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Commodity-Linked Revolving Credit Facility - In February 2022, Vistra Operations
entered into a credit agreement by and among Vistra Operations, Vistra
Intermediate, the lenders, joint lead arrangers and joint bookrunners party
thereto, and Citibank, N.A., as administrative agent and collateral agent. The
Credit Agreement provides for a senior secured commodity-linked revolving credit
facility (the Commodity-Linked Facility). Vistra Operations intends to use the
liquidity provided under the Commodity-Linked Facility to make cash postings as
required under various commodity contracts to which Vistra Operations and its
subsidiaries are parties as power prices increase from time-to time and for
other working capital and general corporate purposes.

In order to support our comprehensive hedging strategy, in May 2022, we entered
into an amendment to our Commodity-Linked Facility to increase the aggregate
available commitments from $1.0 billion to $2.0 billion and to provide the
flexibility, subject to our ability to obtain additional commitments, to further
increase the size of the Commodity-Linked Facility by an additional $1.0 billion
to a facility size of $3.0 billion. Subsequent amendments in May 2022 and June
2022 increased the aggregate available commitments under the Commodity-Linked
Facility from $2.0 billion to $2.25 billion.

On October 5, 2022, Vistra initiated an amendment to the Commodity-Linked
Facility to, among other things, (i) extend the maturity date to October 2023
and (ii) reduce the aggregate available commitments to $1.25 billion. On October
21, 2022, the Commodity-Linked Facility was further amended to increase the
aggregate available commitments to $1.35 billion.

See Note 10 to the Financial Statements for more information concerning the Commodity-Linked Facility.

Power Price, Natural Gas Price and Market Heat Rate Exposure

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments at September 30, 2022 were as follows:

                                        2022      2023
Nuclear/Renewable/Coal Generation:
Texas                                   95  %     92  %
Sunset                                  93  %     77  %
Gas Generation:
Texas                                   90  %     75  %
East                                    99  %     88  %
West                                    90  %     96  %



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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 MMBtu/MWh) on realized pre-tax earnings (in
millions) taking into account the hedge positions noted above for the periods
presented. The residual gas position is calculated based on two steps: first,
calculating the difference 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 September 30, 2022.
                                                                           Balance 2022             2023

Texas:

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

          2          $      10
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price      $         (2)         $      (9)
Gas Generation: $1.00/MWh increase in spark spread                        $          1          $      12
Gas Generation: $1.00/MWh decrease in spark spread                        $         (1)         $     (11)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price  $          1          $     (20)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price  $         (1)         $      14
East:
Gas Generation: $1.00/MWh increase in spark spread                        $          -          $       7
Gas Generation: $1.00/MWh decrease in spark spread                        $          -          $      (6)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price  $          1          $      (6)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price  $         (1)         $       6
West:
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  $          -          $       1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price  $          -          $      (1)
Sunset:
Coal Generation: $2.50/MWh increase in power price                        $          1          $      15
Coal Generation: $2.50/MWh decrease in power price                        $         (1)         $     (14)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price  $          -          $      (8)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price  $          -          $       8



PJM Auction Results

In June 2022, Vistra reported its results from PJM's Reliability Pricing Model
(RPM) auction results for planning year 2023-2024, and the table below lists
clearing price per MW-day and our cleared capacity volumes by zone:
                                          Clearing Price                                         Sunset Segment MW             Total
                                            per MW-day           East Segment MW Cleared              Cleared                MW Cleared
RTO zone                                  $      34.13                     2,890                            -                   2,890
ComEd zone                                $      34.13                     1,151                          408                   1,559
DEOK zone                                 $      34.13                        11                          924                     935
EMAAC zone                                $      49.49                       828                            -                     828
MAAC zone                                 $      49.49                       545                            -                     545
ATSI zone                                 $      34.13                       112                            -                     112
Total                                     $      37.20                     5,537                        1,332                   6,869



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RESULTS OF OPERATIONS

In the three and nine months ended September 30, 2022, our operating segments
delivered strong operating performance with a disciplined focus on cost
management, while generating and selling essential electricity in a safe and
reliable manner. Our performance reflected the stability of our integrated
model, including a diversified generation fleet, retail and commercial and
hedging activities in support of our integrated business. Notably, we hedged
longer-dated revenues and fuel costs to reduce risk and lock in value as forward
power and gas curves moved up materially, and we executed on our share
repurchase strategy.

Consolidated Financial Results - Three and Nine Months Ended September 30, 2022 Compared to Three and Nine Months Ended September 30, 2021

                                       Three Months Ended                    Favorable                  Nine Months Ended                   Favorable
                                          September 30,                    (Unfavorable)                  September 30,                   (Unfavorable)
                                      2022                2021               $ Change                 2022              2021                $ Change
Operating revenues              $    5,146             $ 2,991          $          2,155          $   9,859          $  8,763          $          1,096
Fuel, purchased power costs and
delivery fees                       (3,139)             (1,763)                   (1,376)            (7,580)           (7,827)                      247
Operating costs                       (400)               (372)                      (28)            (1,250)           (1,173)                      (77)
Depreciation and amortization         (390)               (468)                       78             (1,214)           (1,355)                      141
Selling, general and
administrative expenses               (323)               (269)                      (54)              (894)             (771)                     (123)

Impairment of long-lived assets          -                   -                         -                  -               (38)                       38
Operating income (loss)                894                 119                       775             (1,079)           (2,401)                    1,322
Other income                            10                  16                        (6)                88               108                       (20)
Other deductions                        (5)                 (5)                        -                (18)              (13)                       (5)
Interest expense and related
charges                                (71)               (124)                       53               (186)             (288)                      102
Impacts of Tax Receivable
Agreement                               86                  35                        51                (29)               31                       (60)

Income (loss) before income
taxes                                  914                  41                       873             (1,224)           (2,563)                    1,339
Income tax (expense) benefit          (236)                (31)                     (205)               262               569                      (307)
Net income (loss)               $      678             $    10          $            668          $    (962)         $ (1,994)         $          1,032



                                                                                 Three Months Ended September 30, 2022
                                                                                                                   Asset            Eliminations /               Vistra
                             Retail            Texas             East            West            Sunset           Closure         Corporate and Other         Consolidated
Operating revenues         $  3,258          $ 3,627          $ 1,126          $  236          $   280          $     68          $         (3,449)         $       5,146
Fuel, purchased power
costs and delivery fees      (4,161)          (1,119)            (983)           (155)            (144)              (27)                    3,450                 (3,139)
Operating costs                 (43)            (193)             (58)            (10)             (71)              (25)                        -                   (400)
Depreciation and
amortization                    (36)            (135)            (187)              4              (19)                1                       (18)                  (390)
Selling, general and
administrative expenses        (238)             (33)             (18)             (5)             (10)              (11)                       (8)                  (323)

Operating income (loss)      (1,220)           2,147             (120)             70               36                 6                       (25)                   894
Other income                      2                1                1               -                -                 6                         -                     10
Other deductions                 (5)              (1)               -               -                1                 -                         -                     (5)
Interest expense and
related charges                  (4)               9                -               2               (1)               (1)                      (76)                   (71)
Impacts of Tax Receivable
Agreement                         -                -                -               -                -                 -                        86                     86

Income (loss) before
income taxes                 (1,227)           2,156             (119)             72               36                11                       (15)                   914
Income tax expense                -                -                -               -                -                 -                      (236)                  (236)
Net income (loss)          $ (1,227)         $ 2,156          $  (119)         $   72          $    36          $     11          $           (251)         $         678



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Three Months Ended September 30, 2021

                                                                                                              Asset            Eliminations /               Vistra
                             Retail           Texas           East            West           Sunset          Closure         Corporate and Other         Consolidated
Operating revenues         $ 2,160          $  843          $  508          $   90          $  (62)         $   (60)         $           (488)         $       2,991
Fuel, purchased power
costs and delivery fees     (1,095)           (482)           (496)            (78)            (86)             (14)                      488                 (1,763)
Operating costs                (38)           (163)            (57)             (9)            (65)             (40)                        -                   (372)
Depreciation and
amortization                   (53)           (179)           (164)            (15)            (27)             (13)                      (17)                  (468)
Selling, general and
administrative expenses       (192)            (23)            (19)             (7)             (8)             (11)                       (9)                  (269)

Operating income (loss)        782              (4)           (228)            (19)           (248)            (138)                      (26)                   119
Other income                     1               7               -               -               2                6                         -                     16
Other deductions                 -              (2)              -               -              (1)               -                        (2)                    (5)
Interest expense and
related charges                 (2)              3              (5)              1              (1)              (1)                     (119)                  (124)
Impacts of Tax Receivable
Agreement                        -               -               -               -               -                -                        35                     35

Income (loss) before
income taxes                   781               4            (233)            (18)           (248)            (133)                     (112)                    41
Income tax expense              (2)              -               -               -               -                -                       (29)                   (31)
Net income (loss)          $   779          $    4          $ (233)         $  (18)         $ (248)         $  (133)         $           (141)         $          10



Consolidated operating income increased $775 million to $894 million in the
three months ended September 30, 2022 compared to the three months ended
September 30, 2021. The change in results was primarily driven by $320 million
in pre-tax unrealized mark-to-market gains on commodity hedging transactions in
2022 compared to $589 million in pre-tax unrealized mark-to-market losses on
commodity hedging transactions in 2021, which was driven by a decrease in
forward power and natural gas price curves during the three months ended
September 30, 2022 compared to an increase in forward power and natural gas
price curves during the three months ended September 30, 2021. Included within
these unrealized mark-to-market changes are pre-tax net unrealized gains of $217
million and pre-tax net unrealized losses of $357 million in the three months
ended September 30, 2022 and 2021, respectively, due to the discontinuance of
NPNS accounting on retail electric contract portfolios where physical settlement
is no longer considered probable throughout the contract term.

Depreciation expense for the three months ended September 30, 2021 includes an
immaterial out-of-period adjustment to correct for the net understatement of
depreciation expense related to prior periods. See Note 1 to the Financial
Statements.

Interest expense and related charges decreased $53 million to $71 million in the
three months ended September 30, 2022 compared to the three months ended
September 30, 2021 driven by unrealized mark-to-market gains on interest rate
swaps of $90 million in 2022 compared to $13 million in 2021. The change in
unrealized results is driven by an increase in interest rates during the three
months ended September 30, 2022. This favorable variance is partially offset by
an increase in interest paid/accrued of $32 million driven by higher average
borrowings during the three months ended September 30, 2022. See Note 17 to the
Financial Statements.

For the three months ended September 30, 2022 and 2021, the Impacts of the Tax Receivable Agreement totaled income of $86 million and $35 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement obligation.


For the three months ended September 30, 2022, income tax expense totaled $236
million and the effective tax rate was 25.8%. For the three months ended
September 30, 2021, income tax expense totaled $31 million and the effective tax
rate was 75.6%. See Note 6 to the Financial Statements for reconciliation of the
effective rates to the U.S. federal statutory rate.

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                                                                                 Nine Months Ended September 30, 2022
                                                                                                                  Asset            Eliminations /               Vistra
                             Retail            Texas             East            West           Sunset           Closure         Corporate and Other         Consolidated
Operating revenues         $ 6,876          $  1,909          $ 2,400          $  387          $   56          $    296          $         (2,065)         $       9,859
Fuel, purchased power
costs and delivery fees     (3,913)           (2,342)          (2,524)           (279)           (340)             (248)                    2,066      

(7,580)

Operating costs               (111)             (602)            (189)            (32)           (213)             (103)                        -      

(1,250)

Depreciation and
amortization                  (109)             (404)            (545)            (26)            (56)              (22)                      (52)     

(1,214)

Selling, general and
administrative expenses       (622)              (99)             (50)            (17)            (29)              (30)                      (47)                  (894)

Operating income (loss)      2,121            (1,538)            (908)             33            (582)             (107)                      (98)                (1,079)
Other income                     2                65                1               -               -                14                         6                     88
Other deductions               (16)               (2)               -               -               1                (1)                        -                    (18)
Interest expense and
related charges                 (8)               20               (3)              3              (2)               (2)                     (194)                  (186)
Impacts of Tax Receivable
Agreement                        -                 -                -               -               -                 -                       (29)                   (29)

Income (loss) before
income taxes                 2,099            (1,455)            (910)             36            (583)              (96)                     (315)                (1,224)
Income tax benefit               -                 -                -               -               -                 -                       262                    262
Net income (loss)          $ 2,099          $ (1,455)         $  (910)     
   $   36          $ (583)         $    (96)         $            (53)         $        (962)



                                                                                Nine Months Ended September 30, 2021
                                                                                                                 Asset            Eliminations /               Vistra
                             Retail            Texas             East            West           Sunset          Closure         Corporate and Other         Consolidated

Operating revenues $ 5,829 $ 1,458 $ 1,738

    $  171          $  188          $   (79)         $           (542)         $       8,763
Fuel, purchased power
costs and delivery fees     (2,345)           (4,133)          (1,269)           (164)           (384)             (74)                      542       

(7,827)

Operating costs                (96)             (527)            (181)            (26)           (194)            (148)                       (1)      

(1,173)

Depreciation and
amortization                  (160)             (462)            (553)            (30)            (78)             (21)                      (51)      

(1,355)

Selling, general and
administrative expenses       (539)              (62)             (56)            (22)            (24)             (38)                      (30)                  (771)

Impairment of long-lived
assets                           -                 -                -               -               -              (38)                        -                    (38)
Operating income (loss)      2,689            (3,726)            (321)            (71)           (492)            (398)                      (82)                (2,401)
Other income                     1                72                -               -               5               26                         4                    108
Other deductions                (4)               (7)               -               -               -                -                        (2)                   (13)
Interest expense and
related charges                 (7)               10              (11)              9              (1)              (1)                     (287)                  (288)
Impacts of Tax Receivable
Agreement                        -                 -                -               -               -                -                        31                     31

Income (loss) before
income taxes                 2,679            (3,651)            (332)            (62)           (488)            (373)                     (336)                (2,563)
Income tax (expense)
benefit                         (2)                -                -               -               -                -                       571                    569
Net income (loss)          $ 2,677          $ (3,651)         $  (332)         $  (62)         $ (488)         $  (373)         $            235          $      (1,994)



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Operating loss decreased $1.322 billion to $1.079 billion in the nine months
ended September 30, 2022 compared to the nine months ended September 30, 2021.
The change in results is driven by the $2.9 billion realized loss associated
with Winter Storm Uri in the first quarter of 2021. Partially offsetting the
2021 Winter Storm Uri impact, results for the nine months ended September 30,
2022 were unfavorably impacted by a $1.256 billion increase in pre-tax
unrealized mark-to-market losses on derivative positions. Power and natural gas
forward market curves moved up during the nine months ended September 30, 2022
driving the pre-tax unrealized mark-to-market losses on commodity hedging
transactions. Included within these unrealized mark-to-market changes are
pre-tax net unrealized losses of $780 million and $357 million recorded in the
nine months ended September 30, 2022 and 2021, respectively, due to the
discontinuance of NPNS accounting on retail electric contract portfolios where
physical settlement is no longer considered probable throughout the contract
term. We believe the overall increase in forward power and natural gas prices
during 2022 has positioned us to significantly benefit operating results in 2023
and beyond.

Depreciation expense for the nine months ended September 30, 2021 includes an
immaterial out-of-period adjustment to correct for the net understatement of
depreciation expense related to prior periods. See Note 1 to the Financial
Statements.

Interest expense and related charges decreased $102 million to $186 million in
the nine months ended September 30, 2022 compared to the nine months ended
September 30, 2021 driven by unrealized mark-to-market gains on interest rate
swaps of $261 million in 2022 compared to $92 million in 2021 which is due to a
more significant rise in interest rates in the nine months ended September 30,
2022, partially offset by an increase in interest paid/accrued of $75 million
driven by higher average borrowings in 2022. See Note 17 to the Financial
Statements.

For the nine months ended September 30, 2022 and 2021, the Impacts of the Tax
Receivable Agreement totaled expense of $29 million and income of $31 million,
respectively. See Note 7 to the Financial Statements for discussion of the
impacts of the Tax Receivable Agreement obligation.

For the nine months ended September 30, 2022, income tax benefit totaled $262
million and the effective tax rate was 21.4%. For the nine months ended
September 30, 2021, income tax benefit totaled $569 million, and the effective
tax rate was 22.2%. See Note 6 to the Financial Statements for reconciliation of
the effective rates to the U.S. federal statutory rate.

Discussion of Adjusted EBITDA


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

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).

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Adjusted EBITDA - Three and Nine Months Ended September 30, 2022 Compared to
Three and Nine Months Ended September 30, 2021

                                       Three Months Ended                   Favorable                  Nine Months Ended                   Favorable
                                          September 30,                   (Unfavorable)                  September 30,                   (Unfavorable)
                                      2022                2021               $ Change                2022              2021                $ Change
Net income (loss)               $    678               $    10          $  

668 $ (962) $ (1,994) $ 1,032 Income tax expense (benefit) 236

                    31                      205               (262)             (569)                      307
Interest expense and related
charges (a)                           71                   124                      (53)               186               288                      (102)
Depreciation and amortization
(b)                                  413                   489                      (76)             1,277             1,416                      (139)
EBITDA before Adjustments          1,398                   654                      744                239              (859)                    1,098
Unrealized net (gain) loss
resulting from commodity
hedging transactions (c)            (320)                  589                     (909)             2,027               771                     1,256
Generation plant retirement
expenses                               -                     5                       (5)                 4                19                       (15)
Fresh start/purchase accounting
impacts                                -                   (17)                      17                  -               (96)                       96
Impacts of Tax Receivable
Agreement                            (86)                  (35)                     (51)                29               (31)                       60

Non-cash compensation expenses        14                    11                        3                 48                40                         8
Transition and merger expenses        (2)                   (2)                       -                 18               (17)                       35
Impairment of long-lived assets        -                     2                       (2)                 -                40                       (40)

Winter Storm Uri impact (d)          (31)                  (33)                       2               (147)              866                    (1,013)
Other, net                             8                    (1)                       9                 40                11                        29
Adjusted EBITDA                 $    981               $ 1,173          $          (192)         $   2,258          $    744          $          1,514


____________
(a)Includes unrealized mark-to-market net gains on interest rate swaps of $90
million and $13 million for the three months ended September 30, 2022 and 2021,
respectively, and unrealized mark-to-market net gains on interest rate swaps of
$261 million and $92 million for the nine months ended September 30, 2022 and
2021, respectively.
(b)Includes nuclear fuel amortization in the Texas segment of $23 million and
$21 million for the three months ended September 30, 2022 and 2021,
respectively, and $63 million and $61 million for the nine months ended
September 30, 2022 and 2021, respectively.
(c)Net pre-tax unrealized mark-to-market gains on commodity and hedging
transactions were driven by a decrease in power and natural gas price curves
during the three months ended September 30, 2022. Net pre-tax unrealized
mark-to-market losses on commodity and hedging transactions were driven by the
increase in power and natural gas forward market curves during the nine months
ended September 30, 2022. Additionally, we recorded pre-tax net unrealized gains
of $217 million and pre-tax net unrealized losses of $357 million in the three
months ended September 30, 2022 and 2021, respectively, and net unrealized
losses of $780 million and $357 million in the nine months ended September 30,
2022 and 2021, respectively, due to the discontinuance of NPNS accounting on
retail electric contract portfolios where physical settlement is no longer
considered probable throughout the contract term.
(d)For the nine months ended September 30, 2021, includes the following of the
Winter Storm Uri impacts, which we believe are not reflective of our operating
performance: the allocation of ERCOT default uplift charges which are expected
to be paid over several decades under current protocols, accrual of Koch
earn-out amounts that we paid in the second quarter of 2022, future bill credits
related to Winter Storm Uri and Winter Storm Uri related legal fees and other
costs. The adjustment for future bill credits relates to large commercial and
industrial customers that curtailed their usage during Winter Storm Uri and will
reverse and impact Adjusted EBITDA in future periods as the credits are applied
to customer bills. The Company believes the inclusion of the bill credits as a
reduction to Adjusted EBITDA in the years in which such bill credits are applied
more accurately reflects its operating performance. Accordingly, for the three
and nine months ended September 30, 2022 and the three months ended
September 30, 2021, includes reductions to Adjusted EBITDA attributable to bill
credit applications of $32 million, $98 million and $33 million, respectively.
Also includes a reduction to Adjusted EBITDA related to a reduction in the
allocation of ERCOT default uplift charges of zero and $56 million for the three
and nine months ended September 30, 2022, respectively, attributable to ERCOT
receiving payments that reduced the market wide default balance.

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                                                                                     Three Months Ended September 30, 2022
                                                                                                                      Asset            Eliminations /               Vistra
                                   Retail            Texas            East           West           Sunset           Closure         Corporate and Other         Consolidated
Net income (loss)                $ (1,227)         $ 2,156          $ (119)         $ 72          $    36          $     11          $           (251)         $         678
Income tax expense                      -                -               -             -                -                 -                       236                    236
Interest expense and related
charges (a)                             4               (9)              -            (2)               1                 1                        76                     71
Depreciation and amortization
(b)                                    36              158             187            (4)              19                (1)                       18                    413
EBITDA before Adjustments          (1,187)           2,305              68            66               56                11                        79                  1,398
Unrealized net (gain) loss
resulting from hedging
transactions                        1,203           (1,436)             68           (22)             (74)              (59)                        -                   (320)
Generation plant retirement
expenses                                -                -               -             -                1                (1)                        -                      -

Impacts of Tax Receivable
Agreement                               -                -               -             -                -                 -                       (86)                   (86)

Non-cash compensation expenses          -                -               -             -                -                 -                        14                     14
Transition and merger expenses         (2)               -               -             -                -                 -                         -                     (2)

Winter Storm Uri impacts (c)          (32)               1               -             -                -                 -                         -                    (31)
Other, net                             16                3               2             1                9                (8)                      (15)                     8
Adjusted EBITDA                  $     (2)         $   873          $  138          $ 45          $    (8)         $    (57)         $             (8) 
       $         981



____________
(a)Includes $90 million of unrealized mark-to-market net gains on interest rate
swaps.
(b)Includes nuclear fuel amortization of $23 million in Texas segment.
(c)Includes the application of future bill credits to large commercial and
industrial customers that curtailed their usage during Winter Storm Uri.

                                                                                    Three Months Ended September 30, 2021
                                                                                                                  Asset            Eliminations /               Vistra
                                   Retail          Texas           East            West          Sunset          Closure         Corporate and Other         Consolidated
Net income (loss)                 $  779          $   4          $ (233)         $ (18)         $ (248)         $  (133)         $           (141)         $          10
Income tax expense                     2              -                                                               -                        29                     31
Interest expense and related
charges (a)                            2             (3)              5             (1)              1                1                       119                    124
Depreciation and amortization (b)     53            200             164             15              27               13                        17                    489
EBITDA before Adjustments            836            201             (64)            (4)           (220)            (119)                       24                    654
Unrealized net (gain) loss
resulting from hedging
transactions                        (739)           654             254             39             279              102                         -                    589
Generation plant retirement
expenses                               -              -               -              -               -                4                         1                      5
Fresh start/purchase accounting
impacts                               (2)            (2)              -              -              (5)              (8)                        -                    (17)
Impacts of Tax Receivable
Agreement                              -              -               -              -               -                -                       (35)                   (35)

Non-cash compensation expenses         -              -               -              -               -                -                        11                     11
Transition and merger expenses        (4)             -               -              -               -                -                         2                     (2)
Impairment of long-lived assets        -              2               -              -               -                -                         -                      2

Winter Storm Uri impacts (c)         (31)            (2)              -              -               -                -                         -                    (33)
Other, net                             5              5               3              1              (2)               1                       (14)                    (1)
Adjusted EBITDA                   $   65          $ 858          $  193          $  36          $   52          $   (20)         $            (11)         $       1,173


____________
(a)Includes $13 million of unrealized mark-to-market net gains on interest rate
swaps.
(b)Includes nuclear fuel amortization of $21 million in Texas segment.
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(c)Includes the following of the Winter Storm Uri impacts, which we believe are
not reflective of our operating performance: future bill credits related to
Winter Storm Uri, partially offset by the allocation of additional ERCOT default
uplift charges, which are expected to be paid over several decades under current
protocols, and Winter Storm Uri related legal fees and other costs. The
adjustment for future bill credits relates to large commercial and industrial
customers that curtailed their usage during Winter Storm Uri and will reverse
and impact Adjusted EBITDA in future periods as the credits are applied to
customer bills. The Company believes the inclusion of the bill credits as a
reduction to Adjusted EBITDA in the years in which such bill credits are applied
more accurately reflects its operating performance.

                                                                                      Nine Months Ended September 30, 2022
                                                                                                                      Asset             Eliminations /               Vistra
                                   Retail            Texas            East            West          Sunset           Closure         Corporate and Other          Consolidated
Net income (loss)                $ 2,099          $ (1,455)         $ (910)         $  36          $ (583)         $    (96)         $             (53)         $        (962)
Income tax benefit                     -                 -               -              -               -                 -                       (262)                  (262)
Interest expense and related
charges (a)                            8               (20)              3             (3)              2                 2                        194                    186
Depreciation and amortization
(b)                                  109               467             545             26              56                22                         52                  1,277
EBITDA before Adjustments          2,216            (1,008)           (362)            59            (525)              (72)                       (69)                   239
Unrealized net (gain) loss
resulting from hedging
transactions                      (1,602)            2,260             805             49             532               (17)                         -                  2,027
Generation plant retirement
expenses                               -                 -               -              -               6                (2)                         -                      4

Impacts of Tax Receivable
Agreement                              -                 -               -              -               -                 -                         29                     29

Non-cash compensation expenses         -                 -               -              -               -                 -                         48                     48
Transition and merger expenses         7                 -               1              -               -                 -                         10                     18

Winter Storm Uri impacts (c)         (95)              (52)              -              -               -                 -                          -                   (147)
Other, net                            38                21               6              2              12                 5                        (44)                    40
Adjusted EBITDA                  $   564          $  1,221          $  450          $ 110          $   25          $    (86)         $             (26)         $       2,258


____________
(a)Includes $261 million of unrealized mark-to-market net gains on interest rate
swaps.
(b)Includes nuclear fuel amortization of $63 million in Texas segment.
(c)Includes the application of bill credits to large commercial and industrial
customers that curtailed their usage during Winter Storm Uri and a reduction in
the allocation of ERCOT default uplift charges which are expected to be paid
over several decades under current protocols. We estimate bill credit amounts to
be applied in future periods are for the remainder of 2022 (approximately $35
million), 2023 (approximately $52 million), 2024 (approximately $41 million) and
2025 (approximately $1 million).

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                                                                                      Nine Months Ended September 30, 2021
                                                                                                                     Asset             Eliminations /               Vistra
                                   Retail            Texas            East            West          Sunset          Closure         Corporate and Other          Consolidated
Net income (loss)                $ 2,677          $ (3,651)         $ (332)         $ (62)         $ (488)         $  (373)         $             235          $      (1,994)
Income tax expense (benefit)           2                 -               -              -               -                -                       (571)                  (569)
Interest expense and related
charges (a)                            7               (10)             11             (9)              1                1                        287                    288
Depreciation and amortization
(b)                                  160               523             553             30              78               21                         51                  1,416
EBITDA before Adjustments          2,846            (3,138)            232            (41)           (409)            (351)                         2                   (859)
Unrealized net (gain) loss
resulting from hedging
transactions                      (2,840)            2,269             407            120             593              222                          -                    771
Generation plant retirement
expenses                               -                 -               -              -               -               19                          -                     19
Fresh start/purchase accounting
impacts                                1                (3)            (74)             -              (7)             (13)                         -                    (96)
Impacts of Tax Receivable
Agreement                              -                 -               -              -               -                -                        (31)                   (31)

Non-cash compensation expenses         -                 -               -              -               -                -                         40                     40
Transition and merger expenses        (2)                -               -              -               -              (15)                         -                    (17)
Impairment of long-lived assets        -                 2               -              -               -               38                          -                     40

Winter Storm Uri impacts (c)         354               511               -              -               1                -                          -                    866
Other, net                            17                 9               8              2               1                4                        (30)                    11
Adjusted EBITDA                  $   376          $   (350)         $  573          $  81          $  179          $   (96)         $             (19)         $         744


____________
(a)Includes $92 million of unrealized mark-to-market net gains on interest rate
swaps.
(b)Includes nuclear fuel amortization of $61 million in Texas segment.
(c)Includes the following of the Winter Storm Uri impacts, which we believe are
not reflective of our operating performance: the allocation of ERCOT default
uplift charges which are expected to be paid over several decades under current
protocols, accrual of Koch earn-out amounts that we paid in the second quarter
of 2022, future bill credits related to Winter Storm Uri and Winter Storm Uri
related legal fees and other costs. The adjustment for future bill credits
relates to large commercial and industrial customers that curtailed their usage
during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future
periods as the credits are applied to customer bills. The Company believes the
inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in
which such bill credits are applied more accurately reflects its operating
performance.

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Table of Contents Retail Segment - Three and Nine Months Ended September 30, 2022 Compared to Three and Nine Months Ended September 30, 2021

                                            Three Months Ended                 Favorable                 Nine Months Ended                  Favorable
                                               September 30,                 (Unfavorable)                 September 30,                  (Unfavorable)
                                           2022              2021                Change                2022              2021                Change
Operating revenues:
Revenues in ERCOT                      $   2,422          $ 1,917          $           505          $  5,887          $ 4,521          $          1,366
Revenues in Northeast/Midwest                609              624                      (15)            1,800            1,715                        85
Amortization expense                           2                2                        -                 1               (1)                        2
Unrealized net gains (losses) on
hedging activities (a)                       225             (383)                     608              (812)            (406)                     (406)
Total operating revenues                   3,258            2,160                    1,098             6,876            5,829                     1,047
Fuel, purchased power costs and
delivery fees:
Purchases from affiliates                 (2,020)          (1,607)                    (413)           (4,473)          (3,784)                    

(689)

Unrealized net gains (losses) on
hedging activities with affiliates (b)    (1,428)           1,117                   (2,545)            2,409            3,244                      

(835)

Unrealized net gains on hedging
activities                                     -                5                       (5)                5                2                         3
Delivery fees                               (684)            (595)                     (89)           (1,758)          (1,472)                     (286)
Other costs (c)                              (29)             (15)                     (14)              (96)            (335)                      239
Total fuel, purchased power costs and
delivery fees                             (4,161)          (1,095)                  (3,066)           (3,913)          (2,345)                   (1,568)

Net income (loss)                      $  (1,227)         $   779          $        (2,006)         $  2,099          $ 2,677          $           (578)

Adjusted EBITDA                        $      (2)         $    65          $           (67)         $    564          $   376          $            188

Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT                    19,720           17,732                    1,988            50,756           44,215                     6,541
Sales volumes in Northeast/Midwest         8,729           10,034                   (1,305)           26,161           27,558                    

(1,397)

Total retail electricity sales volumes    28,449           27,766                      683            76,917           71,773                     5,144
Weather (North Texas average) -
percent of normal (d):
Cooling degree days                        108.1  %          93.2  %                                   112.1  %          89.6  %
Heating degree days                            -  %             -  %                                   111.8  %         118.1  %


____________
(a)Includes pre-tax unrealized net gains of $217 million and net unrealized
losses of $357 million for the three months ended September 30, 2022 and 2021,
respectively, and pre-tax net unrealized losses of $780 million and $357 million
for the nine months ended September 30, 2022 and 2021, respectively, recognized
due to the discontinuance of NPNS accounting on retail electric contract
portfolios where physical settlement is no longer considered probable throughout
the contract term.
(b)Includes unrealized net gains/(losses) from mark-to-market valuations of
commodity positions with the Texas, East and Sunset segments.
(c)For the nine months ended September 30, 2021, includes $162 million of future
bill credits to large commercial and industrial customers.
(d)Reflects cooling degree days or heating degree days for the region based on
Weather Services International (WSI) data.

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The following table presents changes in net income and Adjusted EBITDA for the
three and nine months ended September 30, 2022 compared to the three and nine
months ended September 30, 2021.
                                                             Three Months Ended         Nine Months Ended
                                                             September 30, 2022        September 30, 2022
                                                              Compared to 2021          Compared to 2021
Winter Storm Uri, including bill credits                     $           (45)         $              453

Timing of commodity costs, including self-help gains in 2021, intra-year seasonality and backwardation on multi-year customer contracts

                                                        (9)                       (232)

Higher margins reflecting ERCOT performance and favorable weather in 2022

                                                           37                          46

Other primarily driven by higher bad debt expense due to higher revenues in 2022

                                                  (50)                        (79)
Change in Adjusted EBITDA                                    $           (67)         $              188

Unfavorable impact of unrealized net gains on hedging activities

                                                            (1,942)                     (1,238)

Future bill credits and other costs related to Winter Storm Uri

                                                                        1                         449
Decrease in depreciation and amortization expenses                        17                          51
Change in transition and merger and other expenses                       (15)                        (28)
Change in net income                                         $        (2,006)         $             (578)



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Table of Contents Generation - Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

Three Months Ended September 30,

                                       Texas                             East                             West                           Sunset
                               2022             2021             2022             2021            2022            2021            2022            2021
Operating revenues:
Electricity sales           $   700          $   462          $   757          $   411          $  178          $  134          $  112          $  183
Capacity revenue from
ISO/RTO                           -                -               14              (13)              -               1               -              39
Sales to affiliates           1,442            1,078              458              413               2               1             120             113
Rolloff of unrealized net
gains (losses) representing
positions settled in the
current period                  253              (17)              57              (56)             54              55             174              45
Unrealized net gains
(losses) on hedging
activities                       19             (153)            (240)             225               1            (101)           (259)           (322)
Unrealized net gains
(losses) on hedging
activities with affiliates    1,213             (527)              80             (472)              1               -             134            (118)
Other revenues                    -                -                -                -               -               -              (1)             (2)
Operating revenues            3,627              843            1,126              508             236              90             280             (62)
Fuel, purchased power costs
and delivery fees:
Fuel for generation
facilities and purchased
power costs                    (975)            (458)          (1,006)            (536)           (120)            (84)           (168)           (199)
Fuel for generation
facilities and purchased
power costs from affiliates      (3)               1                1                1               -               -               1              (1)
Unrealized gains (losses)
from hedging activities         (52)              43               36               49             (34)              7              27             116
Unrealized gains (losses)
on hedging activities with
affiliates                        3                -               (1)               -               -               -              (2)              -
Ancillary and other costs       (92)             (68)             (13)             (10)             (1)             (1)             (2)             (2)
Fuel, purchased power costs
and delivery fees            (1,119)            (482)            (983)            (496)           (155)            (78)           (144)            (86)
Net income (loss)           $ 2,156          $     4          $  (119)         $  (233)         $   72          $  (18)         $   36          $ (248)

Adjusted EBITDA             $   873          $   858          $   138      

$ 193 $ 45 $ 36 $ (8) $ 52 Production volumes (GWh): Natural gas facilities 12,654

            9,597           15,118           14,760           1,460           1,635
Lignite and coal facilities   6,643            7,969                                                                             6,351           8,153
Nuclear facilities            5,009            5,254
Solar facilities                250              135
Capacity factors:
CCGT facilities                69.6  %          52.7  %          62.6  %          60.7  %         65.0  %         72.6  %
Lignite and coal facilities    78.1  %          93.7  %                                                                           55.7  %         71.5  %
Nuclear facilities             98.6  %         103.5  %
Weather - percent of normal
(a):
Cooling degree days           105.2  %          92.4  %         111.2  %         101.3  %        112.9  %         94.5  %        107.7  %        109.6  %
Heating degree days               -  %             -  %         119.6  %          37.2  %            -  %            -  %        111.3  %         47.7  %


____________

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

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                                     Three Months Ended                                                     Three Months Ended
                                        September 30,                                                          September 30,
                                    2022               2021                                                2022               2021
                                                                     Average Market On-Peak Power
Market pricing                                                       Prices ($MWh) (b):
Average ERCOT North power                                            PJM West Hub                     $    111.21          $ 51.37
price ($/MWh)                  $    100.54          $ 38.64          AEP Dayton Hub                   $    106.07          $ 50.29
Average NYMEX Henry Hub                                              NYISO Zone C                     $     87.63          $ 43.95

natural gas price ($/MMBtu) $ 7.96 $ 4.27 Massachusetts Hub

                $     99.52          $ 52.69
Average natural gas price (a):                                       Indiana Hub                      $    109.24          $ 51.59
TetcoM3 ($/MMBtu)              $      7.10          $  3.75          Northern Illinois Hub            $    100.59          $ 48.19

Algonquin Citygates ($/MMBtu) $ 7.57 $ 3.86 CAISO NP15

                       $    109.24          $ 71.25


___________

(a)  Reflects the average of daily quoted prices for the periods presented and
does not reflect costs incurred by us.
(b)Reflects the average of day-ahead quoted prices for the periods presented and
does not necessarily reflect prices we realized.

The following table presents changes in net income (loss) and Adjusted EBITDA
for the three months ended September 30, 2022 compared to the three months ended
September 30, 2021.
                                                             Three Months 

Ended September 30, 2022 Compared to 2021

                                                           Texas              East             West            Sunset

Favorable/(unfavorable) change in revenue net of fuel $ 61 $ (56) $ 8 $ (48) Winter Storm Uri impact

                                         3                -               (1)                -

Favorable/(unfavorable) change in other operating costs (32)

     (1)               2                (8)
Favorable/(unfavorable) change in selling, general and
administrative expenses                                       (18)               2                -                (5)
Other                                                           1                -                -                 1
Change in Adjusted EBITDA                               $      15         

$ (55) $ 9 $ (60) Favorable/(unfavorable) change in depreciation and amortization

                                                   42              (23)              19                 8

Change in unrealized net gains/(losses) on hedging activities

                                                  2,090              186               61               353
Impairment of long-lived assets                                 2                -                -                 -

Generation plant retirement, transition and merger expenses

                                                        -                -                -                (1)
Fresh start/purchase accounting impacts                        (2)               -                -                (5)

Winter Storm Uri impact (ERCOT default uplift and Koch earn-out)

                                                      (3)               -                -                 -
Other (including interest and COVID-19 related
expenses)                                                       8                6                1               (11)
Change in Net income (loss)                             $   2,152          

$ 114 $ 90 $ 284




The change in Texas segment results was primarily driven by unrealized hedging
gains in the three months ended September 30, 2022 compared to unrealized
hedging losses in the three months ended September 30, 2021 due to decreases in
forward power prices in the three months ended September 30, 2022 compared to
increases in forward power prices in the three months ended September 30, 2021.
Additionally, revenue net of fuel is higher in the three months ended
September 30, 2022 compared to the three months ended September 30, 2021 due
primarily to strong generation fleet performance during periods of higher
pricing.

The change in East segment results was primarily driven by lower unrealized
hedging losses in the three months ended September 30, 2022 compared to the
three months ended September 30, 2021 due to decreases in forward power prices
in the three months ended September 30, 2022 compared to increases in forward
power prices in the three months ended September 30, 2021. Additionally, revenue
net of fuel is lower in the three months ended September 30, 2022 compared to
the three months ended September 30, 2021 due primarily to higher-than-expected
migration of customers to default service providers at rates below prevailing
wholesale market prices and lower capacity revenue.

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The change in West segment results was primarily driven by unrealized hedging
gains in the three months ended September 30, 2022 compared to unrealized
hedging losses in the three months ended September 30, 2021 due to decreases in
forward power prices in the three months ended September 30, 2022 compared to
increases in forward power prices in the three months ended September 30, 2021.

The change in Sunset segment results was driven by an unfavorable change in revenue net of fuel due primarily to lower generation volumes from coal plants due to industry-wide fuel delivery challenges in the three months ended September 30, 2022.

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Generation - Nine Months Ended September 30, 2022 Compared to Nine Months Ended
September 30, 2021
                                                                            

Nine Months Ended September 30,

                                        Texas                              East                             West                            Sunset
                               2022              2021              2022             2021            2022            2021             2022             2021
Operating revenues:
Electricity sales           $  1,302          $  1,502          $ 1,975          $   986          $  405          $  302          $   323          $   530
Capacity revenue from
ISO/RTO                            -                 -                4              (14)              -               1               63               99
Sales to affiliates            2,746             2,310            1,371            1,178               5               3              353              293
Rolloff of unrealized net
gains (losses) representing
positions settled in the
current period                   441              (170)             (12)             (24)             52              44              260               20
Unrealized net gains
(losses) on hedging
activities                      (865)              (31)            (359)             357             (79)           (179)            (819)            (472)
Unrealized net gains
(losses) on hedging
activities with affiliates    (1,715)           (2,153)            (580)            (819)              4               -             (118)            (272)
Other revenues                     -                 -                1               74               -               -               (6)             (10)
Operating revenues             1,909             1,458            2,400            1,738             387             171               56              188
Fuel, purchased power costs
and delivery fees:
Fuel for generation
facilities and purchased
power costs                   (1,967)           (2,439)          (2,644)          (1,321)           (249)           (176)            (480)           

(508)

Fuel for generation
facilities and purchased
power costs from affiliates       (6)               (1)               2                -               -               -                2               

(1)

Unrealized (gains) losses
from hedging activities         (119)               85              146               79             (26)             15              143              

131

Unrealized (gains) losses
from hedging activities
with affiliates                   (2)                -                -                -               -               -                2               

-

Ancillary and other costs       (248)           (1,778)             (28)             (27)             (4)             (3)              (7)              

(6)

Fuel, purchased power costs
and delivery fees             (2,342)           (4,133)          (2,524)          (1,269)           (279)           (164)            (340)            (384)

Net income (loss)           $ (1,455)         $ (3,651)         $  (910)         $  (332)         $   36          $  (62)         $  (583)         $  (488)

Adjusted EBITDA             $  1,221          $   (350)         $   450          $   573          $  110          $   81          $    25          $   179
Production volumes (GWh):
Natural gas facilities        26,304            23,142           40,872           40,781           3,525           3,998
Lignite and coal facilities   18,376            19,441                                                                             18,219           21,730
Nuclear facilities            14,369            15,343
Solar facilities                 679               357
Capacity factors:
CCGT facilities                 49.3  %           43.1  %          57.4  %          56.7  %         52.3  %         59.8  %
Lignite and coal facilities     72.9  %           77.1  %                                                                            53.9  %          64.2  %
Nuclear facilities              95.4  %          101.8  %
Weather - percent of normal
(a):
Cooling degree days            110.4  %           89.8  %         108.2  %         107.2  %        111.4  %         95.5  %         113.9  %         112.1  %
Heating degree days            129.4  %          122.9  %          98.9  %          95.3  %         95.4  %        108.2  %         101.6  %          94.4  %


____________

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

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                                     Nine Months Ended                                                     Nine Months Ended
                                       September 30,                                                         September 30,
                                   2022              2021                                                2022               2021
                                                                    Average Market On-Peak Power
Market pricing                                                      Prices ($MWh) (b):

Average ERCOT North power                                           PJM West Hub                     $    87.53          $ 39.95
price
($/MWh)                        $   67.08          $ 186.71          AEP Dayton Hub                   $    83.66          $ 40.15
Average NYMEX Henry Hub                                             NYISO Zone C                     $    70.09          $ 31.94

natural gas price ($/MMBtu) $ 6.66 $ 3.52 Massachusetts Hub

                $    95.91          $ 46.96
Average natural gas price (a):                                      Indiana Hub                      $    86.77          $ 43.99
TetcoM3 ($/MMBtu)              $    6.87          $   3.11          Northern Illinois Hub            $    76.68          $ 37.77

Algonquin Citygates ($/MMBtu) $ 9.46 $ 3.93 CAISO NP15

                       $    75.19          $ 52.96


___________

(a)  Reflects the average of daily quoted prices for the periods presented and
does not reflect costs incurred by us.
(b)Reflects the average of day-ahead quoted prices for the periods presented and
does not necessarily reflect prices we realized.

The following table presents changes in net income (loss) and Adjusted EBITDA
for the nine months ended September 30, 2022 compared to the nine months ended
September 30, 2021.
                                                              Nine Months 

Ended September 30, 2022 Compared to 2021

                                                            Texas              East             West            Sunset

Favorable/(unfavorable) change in revenue net of fuel $ 141 $ (72) $ 31 $ (106) Winter Storm Uri impact

                                      1,551              (50)               -              (17)
Unfavorable change in other operating costs                    (85)              (8)              (7)             (34)
Favorable/(unfavorable) change in selling, general and
administrative expenses                                        (34)               7                5              (11)
Other                                                           (2)               -                -               14
Change in Adjusted EBITDA                                $   1,571          $  (123)         $    29          $  (154)
Favorable change in depreciation and amortization               56                8                4               22

Change in unrealized net gains/(losses) on hedging activities

                                                       9             (398)              71               61
Impairment of long-lived assets                                  2                -                -                -
Generation plant retirement expenses                             -                -                -               (6)
Fresh start/purchase accounting impacts                         (3)             (74)               -               (7)

Winter Storm Uri impact (ERCOT default uplift and Koch earn-out)

                                                      563                -                -                1

Other (including interest and COVID-19 related expenses) (2)

       9               (6)             (12)
Change in Net income (loss)                              $   2,196          

$ (578) $ 98 $ (95)




The change in Texas segment results was primarily driven by the Winter Storm Uri
impacts in 2021. The increases in revenue net of fuel and operating costs are
due to strong generation fleet performance during periods of higher pricing and
inflationary pressures, respectively, in the nine months ended September 30,
2022.

The change in East segment results was primarily driven by higher unrealized
hedging losses in the nine months ended September 30, 2022 compared to the nine
months ended September 30, 2021 due to increases in forward power prices and
favorable Winter Storm Uri impacts recognized in the nine months ended
September 30, 2021. Additionally, revenue net of fuel is lower in the nine
months ended September 30, 2022 compared to the nine months ended September 30,
2021 due primarily to higher-than-expected migration of customers to default
service providers at rates below prevailing wholesale market prices and lower
capacity revenue.

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The change in West segment results was driven by lower unrealized losses in the
nine months ended September 30, 2022 as compared to the nine months ended
September 30, 2021 as forward power prices increased more in the nine months
ended September 30, 2021. Additionally, revenues net of fuel are higher in the
nine months ended September 30, 2022 compared to the nine months ended
September 30, 2021 reflecting higher realized margins from our battery ESS
projects (see Note 2 to the Financial Statements).

The change in Sunset segment results was driven by an unfavorable change in revenue net of fuel due primarily to lower generation volumes from coal plants due to industry-wide fuel delivery challenges in the nine months ended September 30, 2022.

Asset Closure Segment - Three and Nine Months Ended September 30, 2022 Compared to Three and Nine Months Ended September 30, 2021

                                     Three Months Ended                  Favorable                    Nine Months Ended                     Favorable
                                        September 30,                  (Unfavorable)                    September 30,                     (Unfavorable)
                                    2022              2021                Change                    2022                 2021                Change
Operating revenues              $      68          $   (60)         $            128          $      296              $   (79)         $            375
Fuel, purchased power costs and
delivery fees                         (27)             (14)                      (13)               (248)                 (74)                     (174)
Operating costs                 $     (25)         $   (40)         $             15          $     (103)             $  (148)         $             45
Depreciation and amortization           1              (13)                       14                 (22)                 (21)                       (1)
Selling, general and
administrative expenses               (11)             (11)                        -                 (30)                 (38)                        8

Impairment of long-lived assets         -                -                         -                   -                  (38)                       38
Operating income (loss)                 6             (138)                      144                (107)                (398)                      291
Other income                            6                6                         -                  14                   26                       (12)
Other deductions                        -                -                         -                  (1)                   -                        (1)
Interest expense and related
charges                                (1)              (1)                        -                  (2)                  (1)                       (1)

Income (loss) before income
taxes                                  11             (133)                      144                 (96)                (373)                      277

Net income (loss)               $      11          $  (133)         $            144          $      (96)             $  (373)         $            277

Adjusted EBITDA                 $     (57)         $   (20)         $            (37)         $      (86)             $   (96)         $             10
Production volumes (GWh)              811            3,301                    (2,490)              6,670                6,852                      (182)



Results and volumes for the Asset Closure segment include those from the Zimmer
and Joppa generation plants that we retired in May 2022 and September 2022,
respectively. Operating costs for the three and nine months ended September 30,
2022 and 2021 also include ongoing costs associated with the decommissioning and
reclamation of retired plants and mines. The change in Asset Closure segment
results for both the three and nine months ended September 30, 2022 is primarily
due to severance and impairment expense recorded in the three months ended
September 30, 2021, in connection with plant closure announcements (see Note 3
to the Financial Statements).

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Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2022 and 2021. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $2.027 billion and $771 million in unrealized net losses, respectively, for the nine months ended September 30, 2022 and 2021, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

Nine Months Ended September 30,

                                                                               2022                2021
Commodity contract net liability at beginning of period                   $      (866)         $     (75)
Settlements/termination of positions (a)                                        1,166               (202)
Changes in fair value of positions in the portfolio (b)                        (3,193)              (569)

Other activity (c)                                                                 79               (116)
Commodity contract net liability at end of period                         $ 

(2,814) $ (962)

____________

(a)Represents reversals of previously recognized unrealized gains and losses
upon settlement/termination (offsets realized gains and losses recognized in the
settlement period). Excludes changes in fair value in the month the position
settled as well as amounts related to positions entered into, and settled, in
the same month.
(b)Represents unrealized net gains (losses) recognized, reflecting the effect of
changes in fair value. Excludes changes in fair value in the month the position
settled as well as amounts related to positions entered into, and settled, in
the same month.
(c)Represents changes in fair value of positions due to receipt or payment of
cash not reflected in unrealized gains or losses. Amounts are generally related
to premiums related to options purchased or sold as well as certain margin
deposits classified as settlement for certain transactions executed on the CME.

Maturity Table - The following table presents the net commodity contract liability arising from recognition of fair values at September 30, 2022, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

                                        Maturity dates of unrealized 

commodity contract net liability at September 30, 2022

                                       Less than                                                  Excess of
Source of fair value                    1 year            1-3 years           4-5 years            5 years             Total
Prices actively quoted               $     (882)         $    (643)         $       (1)         $        -          $ (1,526)
Prices provided by other
external sources                           (147)              (114)                  4                   -              (257)
Prices based on models                     (377)              (509)               (104)                (41)           (1,031)
Total                                $   (1,406)         $  (1,266)         $     (101)         $      (41)         $ (2,814)



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FINANCIAL CONDITION

Operating Cash Flows

Cash provided by operating activities totaled $92 million for the nine months
ended September 30, 2022 compared to cash used in operating activities of $493
million for the nine months ended September 30, 2021. The favorable change of
$585 million was primarily driven by lower cash from operations in 2021 due to
Winter Storm Uri impacts and $544 million of securitization proceeds from ERCOT
in 2022 (see Note 1 to the Financial Statements), partially offset by margin
deposits of $1.805 billion in 2022 as compared to $767 million in 2021 related
to commodity contracts which support our comprehensive hedging strategy.

Depreciation and amortization expense reported as a reconciling adjustment in
the condensed consolidated statements of cash flows exceeds the amount reported
in the condensed consolidated statements of operations by $361 million and $196
million for the nine months ended September 30, 2022 and 2021, respectively. The
difference represented amortization of nuclear fuel, which is reported as fuel
costs in the condensed consolidated statements of operations consistent with
industry practice, and amortization of intangible net assets and liabilities
that are reported in various other condensed consolidated statements of
operations line items including operating revenues and fuel and purchased power
costs and delivery fees.

Investing Cash Flows

Cash used in investing activities totaled $886 million and $843 million for the
nine months ended September 30, 2022 and 2021, respectively. Capital
expenditures totaled $909 million and $790 million for the nine months ended
September 30, 2022 and 2021, respectively, and consisted of the following:
                                                         Nine Months Ended
                                                           September 30,
                                                          2022            

2021

Capital expenditures, including LTSA prepayments   $     471             $ 

437

Nuclear fuel purchases                             $     173             $  

30

Growth and development expenditures                $     265             $ 323
Capital expenditures                               $     909             $ 790



Cash used in investing activities for the nine months ended September 30, 2022
and 2021 also reflected net sales of environmental allowances of $15 million and
net purchases of environmental allowances of $145 million, respectively. In the
nine months ended September 30, 2022 and 2021, we received insurance proceeds
for reimbursement of capital expenditures of $15 million and $74 million,
respectively.

Financing Cash Flows


Cash provided by financing activities totaled $3 million and $1.279 billion for
the nine months ended September 30, 2022 and 2021, respectively. The change was
primarily driven by:

•the issuance of $1.250 billion principal amount of Vistra Operations senior
unsecured notes in May 2021;
•$1.590 billion in cash paid for share repurchases in 2022, including $114
million of unsettled share repurchases accrued as of December 31, 2021 and
excluding $18 million of unsettled share repurchases accrued as of September 30,
2022, compared to $175 million in cash paid in 2021;
•$500 million in cash received from the sale of a portion of the PJM capacity
that cleared for Planning Years 2021-2022 in 2021; and
•dividends of $76 million paid to preferred stockholders in 2022.

These decreases in cash provided by financing activities are partially offset by:


•the issuance of $1.5 billion principal amount of Vistra Operations senior
secured notes in May 2022; and
•net borrowings of $625 million under the accounts receivable financing
facilities in 2022 compared to net borrowings of $175 million in 2021.

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Debt Activity

The maturities of our long-term debt are relatively modest until 2024. See Note
9 to the Financial Statements for details of the Receivables Facility and
Repurchase Facility and Note 10 to the Financial Statements for details of the
Vistra Operations Credit Facilities, the Commodity-Linked Facility and other
long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2022:

                                                      September 30,         

December 31,

                                                          2022                  2021                Change
Cash and cash equivalents                            $        535          $      1,325          $     (790)
Vistra Operations Credit Facilities - Revolving
Credit Facility                                             1,202                 1,254                 (52)
Vistra Operations - Commodity-Linked Facility (a)           1,701                     -               1,701
Total available liquidity (b)                        $      3,438          

$ 2,579 $ 859

____________

(a)As of September 30, 2022, available capacity reflects the borrowing base
which is lower than the aggregate commitments of $2.25 billion. The
Commodity-Linked Facility was amended in October 2022, decreasing the aggregate
commitments to $1.35 billion and extending the term to October 2023.
(b)Excludes amounts available to be borrowed under the Receivables Facility and
the Repurchase Facility, respectively. See Note 9 to the Financial Statements
for detail on our accounts receivable financing.

The $859 million increase in available liquidity for the nine months ended
September 30, 2022 was primarily driven by $1.5 billion principal amount of
Vistra Operations senior secured notes issued, $1.701 billion in available
capacity under the Commodity-Linked Facility under the aggregate commitments in
effect as of September 30, 2022, $1.0 billion in additional aggregate
commitments under the Revolving Credit Facility resulting from the Credit
Agreement Amendments and $625 million in net cash borrowings under the accounts
receivable financing facilities, partially offset by $1.590 billion in cash paid
for share repurchases, $909 million of capital expenditures (including LTSA
prepayments, nuclear fuel and development and growth expenditures), a $1.052
billion increase in letters of credit outstanding under the Revolving Credit
Facility, $227 million in dividends paid to common stockholders and $76 million
in dividends paid to preferred stockholders.

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


Higher commodity market prices combined with our comprehensive hedging strategy
have resulted in significantly increased collateral posting obligations during
the first nine months of 2022. The majority of this collateral relates to hedges
in place through 2023 and is expected to be returned as we satisfy our
obligations under those contracts. As of November 1, 2022, Vistra had
approximately $4.08 billion of cash and availability under its credit facilities
to meet its liquidity needs. The Company believes it has additional alternatives
to maintain access to liquidity, including drawing upon available liquidity,
accessing additional sources of capital, or reducing capital expenditures,
planned voluntary debt repayments or operating costs.

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 10 to the Financial Statements for
discussion of the Vistra Operations Credit Facilities and the Commodity-Linked
Facility.

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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.

At September 30, 2022, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:


•$3.066 billion in cash has been posted with counterparties as compared to
$1.263 billion posted at December 31, 2021;
•$37 million in cash has been received from counterparties as compared to $39
million received at December 31, 2021;
•$2.635 billion in letters of credit have been posted with counterparties as
compared to $1.558 billion posted at December 31, 2021; and
•$88 million in letters of credit have been received from counterparties as
compared to $35 million received at December 31, 2021.

See Collateral Support Obligations below for information related to collateral posted in accordance with the PUCT and ISO/RTO rules.

Income Tax Payments


In the next 12 months, we do not expect to make federal income tax payments due
to Vistra's NOL carryforwards. We expect to make approximately $45 million in
state income tax payments, offset by $5 million in state tax refunds, and $1
million in TRA payments in the next 12 months.

For the nine months ended September 30, 2022, there were no federal income tax
payments, $27 million in state income tax payments, $8 million in state income
tax refunds and no TRA payments.

Financial Covenants


The Vistra Operations Credit 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 (or, during a collateral suspension period, a
total net leverage ratio not to exceed 5.50 million to 1.00). As of
September 30, 2022, we were in compliance with this financial covenant.

See Note 10 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.

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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 September 30, 2022, Vistra has posted letters of credit in the amount
of $74 million with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate
creditworthiness of parties that participate in the markets operated by those
ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $512
million in the form of letters of credit, $30 million in the form of a surety
bond and $16 million of cash at September 30, 2022 (which is subject to daily
adjustments based on settlement activity with the ISOs/RTOs).

Material Cross Default/Acceleration Provisions


Certain of our contractual arrangements contain provisions that could result in
an event of default if there were 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 under such facilities, which totaled approximately $2.522
billion at September 30, 2022.

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 the Vistra Operations Senior Unsecured Indentures and the Vistra
Operations 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
may result in a cross default under the Vistra Operations Senior Unsecured
Notes, the Senior Secured Notes, the Vistra Operations Credit Facilities, the
Receivables Facility, the Commodity-Linked Facility 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 TXU Energy, Dynegy Energy Services,
Ambit Texas, Value Based Brands and TriEagle, each indirect subsidiaries of
Vistra and originators under the Receivables Facility (Originators), fails to
make a payment of principal or interest on any indebtedness that is outstanding
in a principal amount of at least $300 million, or, in the case of TXU Energy or
any of the other Originators, in a principal amount of at least $50 million,
after the expiration of any applicable grace period, or if other events occur or
circumstances exist under such indebtedness which give rise to a right of the
debtholder to accelerate such indebtedness, or if such indebtedness becomes 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.

The Repurchase Facility contains a cross-default provision. The cross-default
provision applies, among other instances, if an event of default (or similar
event) occurs under the Receivables Facility or the Vistra Operations Credit
Facilities. If this cross-default provision is triggered, a termination event
under the Repurchase Facility would occur and the Repurchase Facility may be
terminated.

Under the Secured 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 Secured LOC Facilities.

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Under the Commodity-Linked Facility, a default under any document evidencing
indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary
for failure to pay principal when due at final maturity or that results in the
acceleration of such indebtedness in an aggregate amount of $300 million or
more, may result in a termination of the Commodity-Linked Facility.

Guarantees

See Note 11 to the Financial Statements for discussion of guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 11 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.

© Edgar Online, source Glimpses

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