Vistra

ANNUAL
REPORT
2 0 2 4

As Lubbock’s electricity market
opened to competition in 2024,
TXU Energy quickly became the
city’s top choice for homes and
businesses. With the power to
switch from the local utility to an
electricity provider of their choice,
tens of thousands of people turned
to TXU Energy for straightforward,
affordable electricity plans–more
than any other provider.
This shift reflects a growing trend
across the U.S., where more cities
and regions are exploring the
benefits of electricity market
competition in a retail electric
market, giving consumers the
ability to choose the provider
that best fits their needs and
usage habits.
In Lubbock, TXU Energy is proud
to serve as the energy provider for
Texas Tech University, Lubbock’s
largest employer. This multi-year
partnership is tailored to meet the
needs of the university’s 40,000+
students, featuring scholarship
investments and significant energy
efficiency rebates.

1
VISTRA CORP. — 2024 ANNUAL REPORT
For Vistra, 2024 was defined by growth, transformation,
and success driven by a One Team mindset. We carried
out our purpose, “Lighting Up Lives, Powering a Better
Way Forward,” through our four strategic priorities.
These continue to guide our strategic decisions and
position Vistra for current and future success.
We started the year strong with the successful close of the Energy
Harbor acquisition on March 1. Our team hit the ground running,
successfully integrating the operations and delivering synergies
exceeding initial expectations. This transformative acquisition
grew our Vistra Vision zero-carbon generation and retail electricity
business, adding approximately 4,000 megawatts of 24/7 nuclear
generation and approximately 1 million retail customers.
Our company now owns and operates the second-largest
competitive nuclear fleet in the country.
Our integrated business model delivered another year of strong
results throughout a variety of pricing and weather conditions.
We concluded the year with $5.656 billion of Ongoing Operations
Adjusted EBITDA1, which was $856 million dollars higher than the
midpoint of the original guidance range announced in May 2024.
We also achieved $2.888 billion of Ongoing Operations Adjusted
Free Cash Flow Before Growth1, exceeding the midpoint of the
original guidance set by $438 million.
Dear Fellow Vistra Stockholders:
Jim Burke
President & Chief
Executive Officer
1) Non-GAAP financial measure. See the “Non-GAAP Reconciliation” tables for further details.

2
VISTRA CORP. — 2024 ANNUAL REPORT
We were encouraged to see the strength of our business and its
improving growth profile recognized with our company’s inclusion
in the S&P 500 index in May 2024. Over the summer, we announced
two power purchase agreements for solar energy with two of the
world’s leading tech companies, totaling over 600 MW—one for
200 MW with Amazon in Texas and another for 405 MW with
Microsoft in Illinois. In the fourth quarter, we completed and brought
online two new solar-plus-storage projects in Illinois, both on the
sites of retired or to-be-retired coal plants, transforming the sites
into renewable energy centers and producing needed generation
for the MISO region.
We remain committed to creating value for our shareholders through
disciplined capital allocation. Our long-term capital allocation
program has generated significant value to shareholders since its
inception in November 2021.
Through Feb. 24, 2025, we executed approximately $4.9 billion of
share repurchases. This program reduced Vistra’s share count by
~30% from November 2021, while the consistent allocation of $300
million in dividends per year resulted in our dividend per share
increasing ~48% since November 2021. On Oct. 30, 2024, our Board
authorized an additional $1 billion for share repurchases expected
to be utilized through 2026. As we reduce the share count each
quarter, we plan for the dividend per share to continue to grow.
The year also marked new expectations for forecasted power
demand with growth rates the industry hasn’t seen since the
1960s, when electrification was in full swing. Multiple avenues are
driving demand growth across the markets we serve, including
potential buildout of data centers, continued reshoring of industrial
activities as evidenced by multiple large chip manufacturing site
buildouts, increased electrification of commercial, industrial, and
residential load across the country, strong population growth,
and electrification of the Permian Basin in Texas/ERCOT.
Vistra’s diverse asset base is well-positioned to navigate these
industry trends while continuing to provide reliable power for our
customers. Our team is acutely focused on strategically positioning
Vistra for success in this new supply/demand environment.
2024 marked
new expectations
for forecasted power
demand.
We remain
committed to
creating value
for our shareholders.

3
VISTRA CORP. — 2024 ANNUAL REPORT
Long-term, Sustainable Value Creation
through the Integrated Business Model
The combination of Vistra’s diverse fleet of generation assets,
growing retail business, and comprehensive hedging program forms
an integrated platform that delivers attractive earnings and enables
the return of significant capital to shareholders while allowing for
continued investment to keep our fleet and our customer value
proposition in a strong competitive position. Our integrated
operations are the cornerstone of our company, and we remain
confident that our best-in-class, efficient, low-cost generation fleet
paired with a stable, customer-centric retail business will continue
to drive Vistra forward well into the future.
RETAIL
Vistra’s retail team provided strong Ongoing Operations Adjusted
EBITDA this year, increasing the ongoing run-rate we expect while
providing best-in-class service our customers can trust. Our retail
team outperformed expectations in 2024, and we expect this
trend to continue into the foreseeable planning horizon. Our retail
team introduced new and creative campaigns while continuing
to increase counts across the markets we serve. Our flagship
retail brand, TXU Energy, held a 5-star rating by the Public Utility
Commission of Texas for 27 straight months, showcasing our
passion for excellence. We also saw our fourth consecutive year
of organic growth in ERCOT, increasing residential customer counts
year-over-year. Adding to an excellent year for retail was the sales
performance of our large business markets team, which ended the
year well ahead of expectations.
GENERATION
This year brought volatile commodity and weather conditions. Our
generation team’s unparalleled drive for results was showcased by
achieving 95%2 commercial availability fleetwide and 92%3 for our
nuclear fleet in 2024. Safety remained our highest priority, with 14
of our plants recognized with OSHA VPP Star rating. This designation
is reserved for exemplary worksites with comprehensive, successful
safety and health management systems; currently, less than 1% of
eligible sites in the country hold this recognition.
2) Commercial availability defined as measure of the ability of the fossil fleets in the Texas, East, and West segments
to meet demand during the highest margin hours.
3) Based on full-year operating performance for the PJM nuclear assets.

4
VISTRA CORP. — 2024 ANNUAL REPORT
The year also brought volatile weather environments. Winter Storm
Heather occurred in January followed by mild winter weather in
February and March, and our power plants remained flexible during
daily operations and rescheduled planned outages to optimize
opportunities when available. In summer, despite mild weather in
Texas and lower wholesale prices across competitive markets, the
generation team capitalized on the volatility by optimizing the run
profile of our generation units and coordinating with our commercial
teams to maximize value from our hedges. Overall, the diverse
conditions allowed Vistra to demonstrate our high-performance
culture, delivering for our customers and our shareholders.
Conclusion
Our goal at Vistra is to be an industry leader in the power space by
combining a “vision” for success with a “tradition” of excellence.
We will continue to deliver value to our customers, communities,
shareholders, and our people—now and in the future. Vistra is
positioned for success, and we are extremely proud of our team’s
tremendous 2024 performance. Vistra is a key player in this dynamic
energy transformation underway across the U.S. and opportunities
are very exciting for our stakeholders. We appreciate you, our
investors, for trusting us and supporting our purpose.
Thank you for your continued interest in Vistra; we look forward
to the year ahead.
Jim Burke
President & Chief Executive Officer
Our retail team
outperformed
growth expectations
in 2024.
Our generation
team achieved
95% commercial
availability
fleet-wide for
the year.
Non-GAAP Financial Measures and Forward-Looking Statements. This letter includes references to Ongoing
Operations Adjusted EBITDA and Ongoing Operations Adjusted Free Cash Flow before Growth which are non-
GAAP financial measures. For reconciliations between our non-GAAP measures and the nearest GAAP measures,
please refer to the tables that follow. As non-GAAP financial measures are not intended to be considered in
isolation or as a substitute for GAAP financial measures, you should carefully read the Form 10-K included in
this Annual Report, which includes our consolidated financial statements prepared in accordance with GAAP.
Additionally, this letter includes statements that, to the extent they are not recitations of historical fact, constitute
forward-looking statements within the meaning of the federal securities laws, and are based on Vistra’s current
expectations and assumptions. For a discussion identifying important factors that could cause actual results to
vary materially from those anticipated in the forward-looking statements, see Vistra’s filings with the Securities and
Exchange Commission including, but not limited to, “Management’s Discussion and Analysis of Financial Condition
and Results of Operations” and “Risk Factors” in the Form 10-K portion of this Annual Report.

5
VISTRA CORP. — 2024 ANNUAL REPORT
Non-GAAP Reconciliations - 2024 Adjusted EBITDA
Twelve Months Ended December 31, 2024 (Unaudited, Millions of Dollars)
Retail
Texas
East
West
Eliminations /
Corp and Other
Ongoing
Operations
Consolidated
Asset Closure
Vistra Corp.
Consolidated
Net income (loss)
$1,216
$2,133
$902
$471
$(1,794)
$2,928
$(116)
$2,812
Income tax expense
0
0
0
0
655
655
0
655
Interest expense and related
charges (a)
54
(46)
(9)
(1)
898
896
4
900
Depreciation and amortization (b)
114
686
1,278
86
66
2,230
0
2,230
EBITDA before Adjustments
1,384
2,773
2,171
556
(175)
6,709
(112)
6,597
Unrealized net (gain) loss resulting from
hedging transactions
52
(790)
(76)
(332)
0
(1,146)
(9)
(1,155)
Purchase accounting impacts
0
1
(12)
0
(14)
(25)
0
(25)
Impacts of Tax Receivable
Agreement (c)
0
0
0
0
(5)
(5)
0
(5)
Non-cash compensation expenses
0
0
0
0
100
100
0
100
Transition and merger expenses
2
1
22
0
111
136
0
136
Decommissioning-related
activities (d)
0
26
(91)
2
0
(63)
0
(63)
ERP system implementation expenses
8
7
5
1
0
21
2
23
Other, net
17
14
(2)
11
(111)
(71)
2
(69)
Adjusted EBITDA
$1,463
$2,032
$2,017
$238
$(94)
$5,656
$(117)
$5,539
Note: Texas and East segments include nuclear PTC revenue estimate of $281 million and $264 million, respectively. See Note 4 to the Financial Statements for additional information.
(a) Includes $53 million of unrealized mark-to-market net losses on interest rate swaps.
(b) Includes nuclear fuel amortization of $105 million and $282 million, respectively, in Texas and East segments.
(c) Includes $10 million gain recognized on the repurchase of TRA Rights in the Twelve Months ended December 31, 2024.
(d) Represents net of all NDT (income) loss of the PJM nuclear facilities, ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets.
Non-GAAP Reconciliations – 2024 Adjusted Free Cash Flow Before Growth
Twelve Months Ended December 31, 2024 (Unaudited, Millions of Dollars)
Ongoing
Operations
Asset
Closure
Vistra
Consolidated
Adjusted EBITDA
$5,656
$(117)
$5,539
Interest paid, net (a)
(939)
0
(939)
Taxes paid
(56)
0
(56)
Change in working capital, margin deposits, and accrued environmental allowance obligations
1,048
0
1,048
Reclamation and remediation expenditures
(39)
(49)
(88)
ERP implementation expenditures
(53)
0
(53)
Transition and merger expenditures
(155)
(1)
(156)
Other changes in other operating assets and liabilities
(757)
25
(732)
Cash provided by (used in) operating activities
4,705
(142)
4,563
Capital expenditures for maintenance including net nuclear fuel purchases and LTSA prepayments (b)
(1,092)
0
(1,092)
Proceeds from sale of transferable investment tax credits
150
0
150
Change in working capital, margin deposits, and accrued environmental allowance obligations
(1,048)
0
(1,048)
Transition and merger expenditures
155
1
156
ERP implementation expenditures
53
0
53
Other net investing activities (c)
(35)
0
(35)
Adjusted FCFbG
$2,888
$(141)
$2,747
(a) Net of interest received.
(b) Excludes $800 million of capital expenditures related to growth and development.
(c) Includes net contributions to nuclear decommissioning trusts and other.

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2024
— OR —
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __ to __
Commission File Number 001-38086
Vistra Corp.
(Exact name of registrant as specified in its charter)
Delaware
36-4833255
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
6555 Sierra Drive
Irving, Texas
75039
(214) 812-4600
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code)
Title of Each Class
Trading
Symbol(s)
Name of Each Exchange on
Which Registered
Securities registered pursuant to Section 12(b) of the Act:
Common stock, par value $0.01 per share
VST
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒No ☐
Indicated by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes ☒No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405
of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such
files). Yes ☒No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or
an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth
company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☒
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any
new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal
control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that
prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in
the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation
received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐No ☒
As of June 30, 2024, the last business day of Vistra Corp.'s most recently completed second fiscal quarter, the aggregate market value of the Vistra
Corp. common stock held by non-affiliates of the registrant was $29,500,179,937 based on the closing sale price as reported on the New York Stock
Exchange.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Class
Outstanding as of February 24, 2025
Common stock, par value $0.01 per share
338,963,642
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive Proxy Statement relating to its 2025 Annual Meeting of Stockholders are incorporated by reference in Part III of
this annual report on Form 10-K.


TABLE OF CONTENTS
PAGE
Glossary of Terms and Abbreviations
iii
Forward-Looking Statements
vii
Industry and Market Information
vii
PART I.
Item 1.
BUSINESS
1
Market Discussion
1
Business Strategy
6
Human Capital Resources
7
Environmental Regulations and Related Considerations
9
Corporate Information
17
Available Information
17
Item 1A.
RISK FACTORS
18
Item 1B.
UNRESOLVED STAFF COMMENTS
44
Item 1C.
CYBERSECURITY
45
Item 2.
PROPERTIES
46
Item 3.
LEGAL PROCEEDINGS
48
Item 4.
MINE SAFETY DISCLOSURES
48
PART II.
Item 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
49
Item 6.
[RESERVED]
50
Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, AND
RESULTS OF OPERATIONS
50
Significant Activities and Events, and Items Influencing Future Performance
51
Critical Accounting Estimates
57
Results of Operations
60
Financial Condition
66
Commitments and Contingencies
72
Changes in Accounting Standards
72
Item 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
72
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
75
Consolidated Statements of Operations
78
Consolidated Statements of Comprehensive Income (Loss)
78
Consolidated Balance Sheets
79
Consolidated Statements of Cash Flows
81
Consolidated Statement of Changes in Equity
83
Notes to Consolidated Financial Statements:
85
1. Business and Significant Accounting Policies
85
2. Acquisitions
91
3. Revenue
94
4. Government Assistance
98
5. Income Taxes
99
6. Property, Plant, and Equipment
102
7. Goodwill and Identifiable Intangible Assets and Liabilities
103
8. Collateral Financing Agreement with Affiliate
106
9. Debt, Credit Facilities, and Financings
107
10. Leases
116
i

11. Derivatives
117
12. Fair Value Measurements
121
13. Asset Retirement Obligations
126
14. Pension and Other Postretirement Employee Benefits (OPEB)
127
15. Commitments and Contingencies
132
16. Equity
142
17. Earnings Per Share
144
18. Stock-Based Compensation
145
19. Segment Information
146
20. Supplementary Financial Information
148
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
151
Item 9A.
CONTROLS AND PROCEDURES
151
Item 9B.
OTHER INFORMATION
153
Item 9C.
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT
INSPECTION
153
PART III.
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
154
Item 11.
EXECUTIVE COMPENSATION
154
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
154
Item 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
154
Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
154
PART IV.
Item 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
155
Item 16.
FORM 10-K SUMMARY
177
Signatures
178
ii

GLOSSARY OF TERMS AND ABBREVIATIONS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Current and Former Related Entities:
Ambit
Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context
BCOP
BCOP Borrower LLC, a subsidiary of Vistra Zero
Crius
Crius Energy Trust and/or its subsidiaries, depending on context
Dynegy
Dynegy Inc., and/or its subsidiaries, depending on context
Dynegy Energy Services
Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/b/a
Dynegy, Better Buy Energy, Brighten Energy, Honor Energy and True Fit Energy),
indirect, wholly owned subsidiaries of Vistra, that are REPs in certain areas of MISO and
PJM, respectively, and are engaged in the retail sale of electricity to residential and
business customers
EFH Corp.
Energy Future Holdings Corp., a holding company and formerly the indirect parent of our
predecessor
Energy Harbor
Energy Harbor Holdings LLC (formerly known as Energy Harbor Corp.), and/or its
subsidiaries, depending on context
Homefield Energy
Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned
subsidiary of Vistra, a REP in certain areas of MISO that is engaged in the retail sale of
electricity to municipal customers
Luminant
subsidiaries of Vistra engaged in competitive market activities consisting of electricity
generation and wholesale energy sales and purchases as well as commodity risk
management
Oncor
Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor
Holdings and formerly an indirect subsidiary of EFH Corp., that is engaged in regulated
electricity transmission and distribution activities
Parent
Vistra Corp.
Public Power
Public Power, LLC (d/b/a Public Power), an indirect, wholly owned subsidiary of Vistra, a
REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale
of electricity to residential and business customers
TCEH
Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of
Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the
parent company of our predecessor, depending on context, that were engaged in electricity
generation and wholesale and retail energy market activities, and whose major subsidiaries
included Luminant and TXU Energy
TriEagle Energy
TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy,
Energy Rewards, Power House Energy and Viridian Energy), an indirect, wholly owned
subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail
sale of electricity to residential and business customers
TXU Energy
TXU Energy Retail Company LLC (d/b/a TXU), an indirect, wholly owned subsidiary of
Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of
electricity to residential and business customers
U.S. Gas & Electric
U.S. Gas and Electric, LLC (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an
indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE,
NYISO and MISO that is engaged in the retail sale of electricity to residential and business
customers
Value Based Brands
Value Based Brands LLC (d/b/a 4Change Energy, Express Energy and Veteran Energy), an
indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT
and is engaged in the retail sale of electricity to residential and business customers
Vistra
Vistra Corp., and/or its subsidiaries, depending on context
Vistra Intermediate
Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra
Vistra Operations
Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the
issuer of certain series of notes (see Note 9 to the Financial Statements) and borrower under
the Vistra Operations Credit Facilities
Vistra Vision
Vistra Vision LLC, an indirect, wholly owned subsidiary of Vistra
Vistra Zero
subsidiaries of Vistra engaged in the operation and development of renewables and energy
storage assets resulting in continued modernization of our generation fleet.
Vistra Zero Operations
Vistra Zero Operating Company, LLC, an indirect, wholly owned subsidiary of Vistra
iii

Transmission System Operators:
CAISO
The California Independent System Operator
ERCOT
Electric Reliability Council of Texas, Inc.
ISO-NE
ISO New England Inc.
MISO
Midcontinent Independent System Operator, Inc.
NYISO
New York Independent System Operator, Inc.
PJM
PJM Interconnection, LLC
Authoritative Organizations:
CFTC
U.S. Commodity Futures Trading Commission
EPA
U.S. Environmental Protection Agency
FERC
U.S. Federal Energy Regulatory Commission
FTC
Federal Trade Commission
IEPA
Illinois Environmental Protection Agency
IPCB
Illinois Pollution Control Board
IRS
U.S. Internal Revenue Service
MSHA
U.S. Mine Safety and Health Administration
NERC
North American Electric Reliability Corporation
NRC
U.S. Nuclear Regulatory Commission
PUCT
Public Utility Commission of Texas
RCT
Railroad Commission of Texas, which among other things, has oversight of lignite mining
activity in Texas, and has jurisdiction over oil and natural gas exploration and production,
permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and
compliance
SEC
U.S. Securities and Exchange Commission
TCEQ
Texas Commission on Environmental Quality
TRE
Texas Reliability Entity, Inc., an independent organization that develops reliability
standards for the ERCOT region and monitors and enforces compliance with NERC
standards and monitors compliance with ERCOT protocols
Rules and Regulations:
CAA
Clean Air Act
ERISA
Employee Retirement Income Security Act of 1974
Exchange Act
Securities Exchange Act of 1934, as amended
IRA
Inflation Reduction Act of 2022
Securities Act
Securities Act of 1933, as amended
General Terms:
2023 Form 10-K
Vistra's annual report on Form 10-K for the year ended December 31, 2023, filed with the
SEC on February 29, 2024
Ambit Transaction
the acquisition of Ambit by an indirect, wholly owned subsidiary of Vistra on November 1,
2019 (Ambit Acquisition Date)
ARO
asset retirement and mining reclamation obligation
BCOP Credit Agreement
credit agreement, dated as of December 16, 2024 (as amended, restated, amended and
restated, supplemented and/or otherwise modified from time to time), by and among
BCOP, the lenders and issuing banks party thereto, the administrative agent, and collateral
agent and the other parties named therein
CCGT
combined cycle natural gas turbine
CCR
coal combustion residuals
CME
Chicago Mercantile Exchange
CO2
carbon dioxide
iv

Crius Transaction
the acquisition of equity interests of two wholly owned subsidiaries of Crius that indirectly
owned the operating business of Crius by an indirect, wholly owned subsidiary of Vistra on
July 15, 2019 (Crius Acquisition Date)
CT
combustion turbine
Dynegy Merger
the merger of Dynegy with and into Vistra, with Vistra as the surviving corporation, on
April 9, 2018, the date Vistra and Dynegy completed the transactions contemplated by the
Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra and
Dynegy (Dynegy Merger Date)
EBITDA
earnings (net income) before interest expense, income taxes, depreciation and amortization
Effective Date
October 3, 2016, the date our predecessor completed its reorganization under Chapter 11 of
the U.S. Bankruptcy Code
ESG
environmental, social and governance
ESS
energy storage system
Fitch
Fitch Ratings Inc. (a credit rating agency)
GAAP
generally accepted accounting principles
GHG
greenhouse gas
GWh
gigawatt-hours
Green Finance Framework
Framework adopted by the Company and made available on its website pursuant to which
the Company may issue financial instruments to fund new or existing projects that support
renewable energy and energy efficiency, with alignment to the Company's environmental,
social, and governance strategy
Heat Rate
Heat Rate is a measure of the efficiency of converting a fuel source to electricity
ISO
independent system operator
ITC
investment tax credit
kW
kilowatt
LIBOR
London Interbank Offered Rate, an interest rate at which banks can borrow funds, in
marketable size, from other banks in the London interbank market
load
demand for electricity
LTSA
long-term service agreements for plant maintenance
Market Heat Rate
Market Heat Rate is the implied relationship between wholesale electricity prices and
natural gas prices and is calculated by dividing the wholesale market price of electricity,
which is based on the price offer of the marginal supplier (generally natural gas plants), by
the market price of natural gas.
MMBtu
million British thermal units
Moody's
Moody's Investors Service, Inc. (a credit rating agency)
MW
megawatts
MWh
megawatt-hours
NOX
nitrogen oxide
NYMEX
the New York Mercantile Exchange, a commodity derivatives exchange
NYSE
New York Stock Exchange
OPEB
postretirement employee benefits other than pensions
PrefCo Preferred Stock Sale
as part of the tax-free spin-off from EFH Corp. executed pursuant to the Third Amended
Joint Plan of Reorganization filed by the parent company of our predecessor in August
2016 and confirmed by the U.S. Bankruptcy Court for the District of Delaware in August
2016 solely with respect to our predecessor (Plan of Reorganization) on the Effective Date,
the contribution of certain of the assets of the predecessor and its subsidiaries by a
subsidiary of TEX Energy LLC to Vistra Preferred Inc. (PrefCo) in exchange for all of
PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
PTC
production tax credit
REP
retail electric provider
RTO
regional transmission organization
S&P
Standard & Poor's Ratings (a credit rating agency)
Series A Preferred Stock
Vistra's 8.0% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred
Stock, $0.01 par value, with a liquidation preference of $1,000 per share
v

Series B Preferred Stock
Vistra's 7.0% Series B Fixed-Rate Reset Cumulative Green Redeemable Perpetual
Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Series C Preferred Stock
Vistra's 8.875% Series C Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred
Stock, $0.01 par value, with a liquidation preference of $1,000 per share
SG&A
selling, general, and administrative
SO2
sulfur dioxide
SOFR
Secured Overnight Financing Rate, the average rate at which institutions can borrow U.S.
dollars overnight while posting U.S. Treasury Bonds as collateral
ST
steam turbine
Tax Matters Agreement
Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., Energy
Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC
TRA
Amended and Restated Tax Receivable Agreement, containing certain rights (TRA Rights)
to receive payments from Vistra related to certain tax benefits, including benefits realized
as a result of certain transactions entered into at the emergence of our predecessor from
reorganization under Chapter 11 of the U.S. Bankruptcy Code as subsidiaries of a newly
formed company, Vistra, on the Effective Date
TWh
terawatt-hours
U.S.
United States of America
Vistra Operations Commodity-
Linked Credit Agreement
credit agreement, dated as of February 4, 2022 (as amended, restated, amended and
restated, supplemented, and/or otherwise modified from time to time) by and among Vistra
Operations, Vistra Intermediate, the lenders party thereto, the other credit parties thereto,
the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit
Agreement
credit agreement, dated as of October 3, 2016 (as amended, restated, amended and restated,
supplemented and/or otherwise modified from time to time), by and among Vistra
Operations, Vistra Intermediate, the lenders party thereto, the letter of credit issuers party
thereto, the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit
Facilities
Vistra Operations senior secured financing facilities (see Note 9 to the Financial
Statements)
Vistra Zero Credit Agreement
credit agreement, dated as of March 26, 2024 (as amended, restated, amended and restated,
supplemented and/or otherwise modified from time to time), by and among Vistra Zero
Operating Company, LLC, the lenders party thereto, the administrative agent, and collateral
agent, and the other parties named therein
vi

FORWARD-LOOKING STATEMENTS
This annual report on Form 10-K contains forward-looking statements that involve risk and uncertainties. All statements,
other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or
otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such
matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity,
dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of
power generation assets, market and industry developments and the growth of our businesses and operations, including
potential transactions with large load facilities at our nuclear and natural gas plants (often, but not always, through the use of
words or phrases such as "intends," "plans," "potential," "will likely," "unlikely," "believe," "expect," "anticipated," "estimate,"
"should," "could," "may," "projection," "forecast," "target," "goal," "objective," and "outlook"), are forward-looking statements.
Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions,
any such forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion
in Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations
in this annual report on Form 10-K.
Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we
undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is
made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not
possible for us to predict them. In addition, we may be unable to assess the impact of any such event or condition or the extent
to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those
contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking
statements.
INDUSTRY AND MARKET INFORMATION
Certain industry and market data and other statistical information used throughout this report are based on independent
industry publications, government publications, reports by market research firms or other published independent sources,
including certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of
states in which we operate, and NYMEX. We did not commission any of these publications, reports or other sources. Some data
is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources
listed above. Industry publications, reports, and other sources generally state that they have obtained information from sources
believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of
these studies, publications, reports, and other sources is reliable, we have not independently investigated or verified the
information contained or referred to therein and make no representation as to the accuracy or completeness of such information.
Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions
were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used
throughout this report involve risks and uncertainties and are subject to change based on various factors.
vii


PART I
Item 1. BUSINESS
References in this report to "we," "our," "us," and "the Company" are to Vistra and/or its subsidiaries, as apparent in the
context. See Glossary of Terms and Abbreviations for defined terms.
General
Vistra is an integrated retail electricity and power generation company. We combine an innovative, customer-centric
approach to retail sales with safe, reliable, diverse, and efficient power generation. Our integrated power generation and
wholesale operation allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost. The
integrated model enables us to structure products and contracts in a way that offers significant value compared to stand-alone
retail electric providers.
The Company brings its products and services to market in 18 states and the District of Columbia, including all major
competitive wholesale power markets in the U.S. We serve approximately 5 million residential, commercial, and industrial
retail customers with electricity and natural gas. Our generation fleet totals approximately 41,000 megawatts of generation
capacity powered by a diverse portfolio, including natural gas, nuclear, coal, solar, and battery energy storage facilities.
Market Discussion
The operations of Vistra, as an integrated retail electricity and power generation company, are further aligned into five
reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. Our Texas, East, and West
segments include our electricity generation operations, and our Asset Closure segment is engaged in the decommissioning and
reclamation of retired plants and mines. In the fourth quarter of 2024, we updated our reportable segments to reflect changes in
how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance, and allocates
resources by eliminating the Sunset segment. The results of the plants previously included in the Sunset segment are now
reflected in the Texas and East segments based on their respective geography.
Retail Operations
Vistra is one of the largest competitive residential retail electricity providers in the U.S. Our retail operations are engaged
in retail sales of electricity, natural gas, and related services to approximately 5 million customers. Substantially all of our retail
activities are conducted by TXU Energy, Ambit Energy, Dynegy Energy Services, Homefield Energy, and U.S. Gas & Electric
across 16 U.S. states and the District of Columbia. The largest portion of our retail operations are in Texas, where we provide
retail electricity to approximately 2.6 million customers.
Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in
Texas for over 20 years, is registered and protected by trademark law. We also own the trade names for Ambit Energy, Dynegy
Energy Services, Homefield Energy, TriEagle Energy, Public Power, and U.S. Gas & Electric.
We believe that we have differentiated ourselves by providing a distinctive customer experience predicated on delivering
reliable and innovative power products and solutions to our customers, including 100% wind and solar options, as well as
thermostats, dashboards, and other programs designed to encourage reduced electricity consumption and increased energy
efficiency. Our distinctive power products give our customers choice, convenience, and control over how and when they use
electricity and related services.
1

Electricity Generation Operations
Vistra is the largest competitive power generator in the U.S. as measured by MWh of generation capacity. At
December 31, 2024, our generating capacity was powered by the following:
Primary Fuel
Technology
Net Capacity (MW)
% of Net Capacity
Natural Gas
CCGT, CT or ST
24,120
59%
Coal
ST
8,428
21%
Uranium
Nuclear
6,448
16%
Renewable
Solar/Battery
1,474
4%
Fuel Oil
CT
187
—%
Total
40,657
100%
Our natural gas-fueled generation fleet is comprised of 23 CCGT generation facilities totaling 19,742 MW and 10 peaking
generation facilities totaling 4,378 MW. We satisfy our fuel requirements at these facilities through a combination of spot
market and near-term purchase contracts. Additionally, we have near-term natural gas transportation agreements and natural gas
storage agreements in place to ensure fleet reliability.
Our coal/lignite-fueled generation fleet is comprised of seven generation facilities totaling 8,428 MW of generation
capacity. We meet our fuel requirements at our coal-fueled generation facilities in PJM and MISO with coal purchased from
multiple suppliers under contracts of various lengths and transported to the facilities by either railcar or barges. We meet our
fuel requirements in ERCOT using lignite that we mine at our generation facilities and coal purchased and transported by
railcar.
We own and operate six nuclear generation units at four different facilities:
Unit
ISO
Net Capacity (MW)
Refueling Outage
Frequency
License Expiration Date
Comanche Peak Unit 1
ERCOT
1,200
18 Months
2050
Comanche Peak Unit 2
ERCOT
1,200
18 Months
2053
Beaver Valley Unit 1
PJM
939
18 Months
2036
Beaver Valley Unit 2
PJM
933
18 Months
2047
Perry
PJM
1,268
24 Months
2026 (a)
Davis-Besse
PJM
908
24 Months
2037
Total
6,448
___________
(a) In 2023, an application for a license renewal at our Perry nuclear plant was filed with the NRC to extend our license
through 2046.
Nuclear units are generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages for each unit
are scheduled to occur during the spring or fall off-peak demand periods. While one unit is undergoing a refueling outage at
dual-unit facilities, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance,
modification, and testing activities are completed that cannot be accomplished when the unit is in operation.
We have contracts in place for all of our nuclear fuel requirements through 2029. We do not anticipate any significant
difficulties in acquiring uranium and contracting for associated conversion, enrichment, and fabrication services in the
foreseeable future. We continue to monitor developments regarding the availability of nuclear fuel that may arise out of the
Russia and Ukraine conflict. See Item 7. Management's Discussion and Analysis of Financial Condition, and Results of
Operations – Significant Activities and Events, and Items Influencing Future Performance – Macroeconomic Conditions.
Our generation operations by segment are represented in the following table:
Segment
Net Capacity (MW)
% of Net Capacity
ISO/RTO
Texas
19,031
47%
ERCOT
East
19,746
49%
PJM, ISO-NE, MISO, and NYISO
West
1,880
4%
CAISO
Total
40,657
100%
2

Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) — ISOs and RTOs manage the
transmission infrastructure and markets across regions, separate from our operations. They dispatch generation facilities,
ensuring efficient and reliable transmission system operation. ISOs/RTOs administer short-term energy and ancillary service
markets, typically day-ahead and real-time, and some also manage long-term planning reserves through various capacity
markets. They impose bid and price limits in wholesale power markets. NERC regions and ISOs/RTOs often have different
geographic footprints, and while there may be geographic overlap between NERC regions and ISOs/RTOs, their respective
roles and responsibilities do not generally overlap.
In centrally dispatched market structures (e.g., ERCOT, PJM, ISO-NE, NYISO, MISO, CAISO), all generators receive
the same price for energy based on the bid price of the last MWh needed to balance supply and demand. Prices vary within
different zones due to transmission losses and congestion. For example, if a less efficient natural gas unit is needed to meet
demand, its offer price sets the market clearing price for all dispatched generation in that market, regardless of other units' offer
prices. Generators receive the location-based marginal price for their output.
ERCOT — ERCOT is an ISO that manages the flow of electricity from approximately 103,600 MW of expected Summer
2024 peak generation capacity to approximately 27 million Texas customers, representing approximately 90% of the state's
electric load.
As an energy-only market, ERCOT's market design is distinct from other competitive electricity markets in the U.S. Other
markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/or
capacity markets. In contrast, ERCOT's resource adequacy is currently predominately dependent on energy-market price
signals. The Texas Legislature mandated the development of an ancillary service, the Dispatchable Reliability Reserve Service
(DRRS), to address intra-hour operations challenges. The PUCT voted in December 2024 to have ERCOT develop DRRS so it
can address both operational issues and resource adequacy issues. ERCOT is continuing work on DRRS, and it has not been
implemented as of the date hereof. In 2014, ERCOT implemented the Operating Reserve Demand Curve (ORDC), pursuant to
which wholesale electricity prices in the real-time electricity market increase automatically as available operating reserves
decrease below defined threshold levels, creating a price adder. The slope of the ORDC curve is determined through a
mathematical loss of load probability calculation using forecasted reserves and historical data. In both March 2019 and March
2020, ERCOT implemented 0.25 standard deviation shifts in the loss of load probability calculation and moved to using a
single blended ORDC curve; these changes resulted in a more rapid escalation in power prices as operating reserves fall below
defined thresholds. Effective January 1, 2022, when operating reserves drop to 3,000 MW or less, the ORDC automatically
adjusts power prices to $5,000/MWh which is equal to the high system-wide offer cap. When ERCOT implements real-time co-
optimization, discussed below, the ORDC will be replaced by ancillary service demand curves that are designed to mimic the
operation of the ORDC. ERCOT also calculates the "peaker net margin" based on revenues a hypothetical unhedged peaking
unit would collect in the market. If the peaker net margin exceeds a certain threshold, the system-wide offer cap is reduced to
the low system-wide offer cap of $2,000/MWh for the remainder of the calendar year. In December 2023, the PUCT also
approved an Emergency Pricing Program that temporarily lowers the system-wide offer cap to $2,000/MWh if prices have been
at the cap for 12 hours in a rolling 24-hour period. Historically, high demand due to elevated temperatures in the summer
months or high demand due to reduced temperatures in the winter months, combined with underperformance of wind
generation, has created the conditions during which the ORDC contributes meaningfully to power prices. Extreme weather
conditions can also lead to scarcity conditions regardless of season. Other than during periods of "scarcity pricing," the price of
power is typically set by natural gas-fueled generation facilities (see Item 7. Management's Discussion and Analysis of
Financial Condition, and Results of Operations – Significant Activities and Events, and Items Influencing Future Performance).
3

Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market. The day-ahead
market is a voluntary, financial electricity market conducted the day before each operating day in which generators and
purchasers of electricity may bid for one or more hours of electricity supply or consumption. The real-time market is a physical
market in which electricity is dispatched and priced in five-minute intervals. The day-ahead market provides market participants
with visibility into where prices are expected to clear, and the prices are not impacted by subsequent events. Conversely, the
real-time market exposes purchasers to the risk of transient operational events and price spikes. These two markets allow
market participants to manage their risk profile by adjusting their participation in each market. In addition, ERCOT uses
ancillary services to maintain system reliability, including regulation service, responsive reserve service, and non-spinning
reserve service. Ancillary services are provided by generators and qualified loads to help maintain the stable voltage and
frequency requirements of the transmission system. ERCOT currently procures ancillary services in the day-ahead market, but
plans to implement co-optimization of energy and ancillary services in the real-time market by the end of 2025. Because
ERCOT has one of the highest concentrations of wind and solar capacity generation among U.S. markets, the ERCOT market is
more susceptible to fluctuations in wholesale electricity supply due to intermittent wind and solar production, making ERCOT
more vulnerable to periods of generation scarcity. ERCOT implemented the ERCOT Contingency Reserve Service (ECRS) in
June 2023 to further address the need for operating reserves to manage load and intermittent resource output uncertainty.
PJM — PJM is an RTO that manages the flow of electricity from approximately 183,000 MW of generation capacity to
approximately 65 million customers in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey,
North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.
Like ERCOT, PJM administers markets for wholesale electricity and provides transmission planning for the region,
utilizing a locational marginal pricing (LMP) methodology which calculates a price for every generator and load point within
PJM. PJM operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services.
PJM also administers a forward capacity auction, the Reliability Pricing Model (RPM), which establishes a long-term market
for capacity. We have participated in RPM auctions for years up to and including PJM's planning year 2025-2026, which ends
May 31, 2026. PJM's RPM auction for planning year 2026-2027 was delayed and is expected to be run in July 2025. We also
enter into bilateral capacity transactions. PJM's Capacity Performance (CP) rules were designed to improve system reliability
and include penalties for under-performing units and reward for over-performing units during shortage events. Full transition of
the capacity market to CP rules occurred in planning year 2020-2021. An independent market monitor continually monitors
PJM markets to ensure a robust, competitive market and to identify improper behavior by any entity.
ISO-NE — ISO-NE is an ISO that manages the flow of electricity from approximately 30,600 MW of winter generation
capacity to approximately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode
Island, and Maine.
ISO-NE dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at
LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through
real-time and day-ahead auctions. Energy prices vary among the locations in ISO-NE and are largely influenced by
transmission constraints and fuel supply. ISO-NE offers the Forward Capacity Market where capacity prices are determined
through auctions currently run three years prior to the capacity delivery year. ISO-NE is working with stakeholders to transition
to a prompt capacity market for the delivery year starting in June 2028. Performance incentive rules have the potential to
increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while
penalizing those that produce less than the required level.
NYISO — NYISO is an ISO that manages the flow of electricity from approximately 37,100 MW of installed summer
generation capacity to approximately 20 million New York customers.
NYISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at
LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through
real-time and day-ahead auctions. Energy prices vary among the regional zones and locations in the NYISO and are largely
influenced by transmission constraints and fuel supply. NYISO offers the Installed Capacity Market, a forward capacity market
where capacity prices are determined through auctions. Strip auctions occur one to two months prior to the commencement of a
six-month seasonal planning period. Subsequent auctions provide an opportunity to sell excess capacity for the balance of the
seasonal planning period or the upcoming month. Due to the short-term nature of the NYISO-operated capacity auctions and a
relatively liquid bilateral market for NYISO capacity products, our Independence facility sells a significant portion of its
capacity through bilateral transactions. The balance is cleared through the seasonal and monthly capacity auctions.
4

MISO — MISO is an RTO that manages the flow of electricity from approximately 202,000 MW of installed generation
capacity to approximately 45 million customers in all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan,
Kentucky, Indiana, Illinois, Missouri, Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota, and Manitoba, Canada.
MISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs.
Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time
and day-ahead auctions. Energy prices vary among the regional zones and locations in MISO and are largely influenced by
transmission constraints and fuel supply. An independent market monitor is responsible for evaluating the performance of the
markets and identifying conduct by market participants or MISO that may compromise the efficiency or distort the outcome of
the markets.
MISO administers a one-year Planning Resource Auction (PRA) for the next planning year from June 1st of the current
year to May 31st of the following year. MISO's PRA currently uses a vertical demand curve that can result in more volatile
capacity prices. In 2022, FERC approved MISO's proposal to change the annual Planning Resource Auction into a seasonal
auction, effective for the 2023-2024 planning year. Starting with the PRA for the 2025-2026 planning year, MISO will begin
using a sloped demand curve. We participate in these auctions with open capacity that has not been committed through bilateral
or retail transactions. We also participate in the MISO annual and monthly financial transmission rights auctions to manage the
cost of our transmission congestion, as measured by the congestion component of the LMP price differential between two
points on the transmission grid across the market area.
CAISO — CAISO is an ISO that manages the flow of electricity to approximately 32 million customers primarily in
California, representing approximately 80% percent of the state's electric load.
Energy is priced in CAISO utilizing an LMP methodology. The capacity market is comprised of Generic, Flexible, and
Local Resource Adequacy (RA) Capacity, which is administered by the California Public Utilities Commission (CPUC). Unlike
other centrally cleared capacity markets, the resource adequacy markets in California are primarily bilaterally traded markets. In
2020, the CPUC introduced a central procurement entity for Local RA Capacity effective for the 2023 compliance year. The
central procurement entity runs a pay-as-bid auction for Local RA Capacity. In November 2016, CAISO implemented a
voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market. The
voluntary Competitive Solicitation Process, which FERC approved in October 2015, is a modification to the Capacity
Procurement Mechanism (CPM) and provides another avenue to sell RA capacity.
Wholesale Operations — Our wholesale commodity risk management group is responsible for dispatching our generation
fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the
generation fleet production with our retail customer and wholesale sales opportunities. Market demand, also known as load,
faced by electric power systems, such as those we operate in, varies from moment to moment as a result of changes in business
and residential demand, which is often driven by weather. Unlike most other commodities, the production and consumption of
electricity must remain balanced on an instantaneous basis. There is a certain baseline demand for electricity across an electric
power system that occurs throughout the day, which is typically satisfied by baseload generation units with low variable
operating costs. Baseload generation units can also increase output to satisfy certain incremental demand and reduce output
when demand is unusually low. Intermediate/load-following generation units, which can more efficiently change their output to
satisfy increases in demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in
demand or unexpected changes in supply created by reduced generation from renewable resources or other generator outages.
Peak daily loads may be satisfied by peaking units. Peaking units are typically the most expensive to operate, but they can
quickly start up and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load following units, and
peaking units are dispatched into the ISO/RTO grid in order from lowest to highest variable cost. Price formation is typically
based on the highest variable cost unit that clears the market to satisfy system demand at a given point in time.
Our commodity risk management group enters into electricity, natural gas, and other commodity derivative contracts to
reduce exposure to price fluctuations with the goal of reducing volatility of future revenues and fuel costs for our generation
facilities and purchased power costs for our Retail segment.
5

Seasonality
The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results
are impacted by extreme or sustained weather conditions and may fluctuate on a seasonal basis. Typically, demand for and the
price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for
and price of natural gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme
winter weather have made, and may make, such fluctuations more pronounced. The pattern of this fluctuation may change
depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.
Competition
Competition in the markets in which we operate is impacted by electricity and fuel prices, congestion along the power
grid, subsidies provided by state and federal governments for new and existing generation facilities, including renewables
generation and battery ESS, new market entrants, construction of new generation assets, technological advances in power
generation, the actions of environmental and other regulatory authorities, and other factors. We primarily compete with other
electricity generators and retailers based on our ability to generate electric supply, market and sell electricity at competitive
prices, and efficiently utilize transportation from third-party pipelines and transmission from electric utilities to deliver
electricity to end-users. Competitors in the generation and retail power markets in which we participate include numerous
regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities, independent
power producers, REPs, and other energy marketers. See Item 1A. Risk Factors for additional information concerning the risks
faced with respect to the markets in which we operate.
Business Strategy
Vistra is the largest producer of power in deregulated markets in the U.S. with annual expected generation of over 200
TWh as of December 31, 2024.
Vistra is guided by four core principles:
•
We do business the right way. Every decision we make and action we take will be evidence of the utmost integrity
and compliance.
•
We compete to win. We will create the leading integrated energy company with an unmatched work ethic, an
analysis-driven and disciplined culture with strong leadership and decision-making throughout the organization.
•
We work as a team. We are committed to each other, everything we do and to the success of our company.
•
We care about our key stakeholders. We respect our fellow employees, we focus on our customers, and we care about
our communities where we live and do business. We will maintain productive and respectful relationship with our
legislators, regulators and community leaders.
To align with our four core principles, our focus is on the execution of our strategic priorities as follows:
Long-term, attractive earnings profile through the integrated business model. Our integrated business model distinguishes
us from our electricity competitors as it combines our reliable and efficient diversified generation fleet totaling approximately
41,000 MW of capacity, with our commercial operations, including commodity risk management capabilities, and our best-in-
class retail energy platform. We believe integrating retail with power generation stands as a fundamental competitive advantage
that mitigates the impact of commodity price fluctuations and enhances the stability and predictability of our cash flows.
Disciplined capital allocation. We strive to make thoughtful decisions when allocating our free cash flow to balance
growth opportunities with returning capital to our stakeholders through share repurchases, dividends, and debt reduction.
Maintaining a resilient balance sheet. We seek to manage our financial leverage by maintaining a strong balance sheet
which ensures our access to diverse sources of liquidity. We believe this provides financial flexibility for our capital allocation
decisions, including executing on organic growth opportunities, engaging in mergers and acquisitions, opportunistic debt
reduction, or returning capital to our stockholders.
6

Strategic energy transition that supports the reliability, affordability, and sustainability of the electric grid. As one of the
largest electricity generators in the U.S., Vistra has led the way in decarbonization efforts and is committed to sustainability,
setting aggressive targets, and transitioning our fleet to low-to-no carbon resources, all while balancing our obligations to our
stakeholders. While the way we generate electricity may be changing, our essential role in providing reliable and affordable
electricity is not.
Human Capital Resources
Vistra's approach to human capital management is guided by our core values. Our core values apply to all employees,
suppliers and contractors and guide how we interact with our partner companies, communities, the environment and all other
stakeholders. We aim to conduct all aspects of our business in accordance with these core values, which serve as the cultural
foundation of the Company.
Vistra believes our most valuable asset is our talented, dedicated and dynamic group of employees who work together to
achieve our objectives, and our top priority is ensuring their safety. As of December 31, 2024, we had approximately 6,850 full-
time employees, including approximately 1,940 employees under collective bargaining agreements.
Safety
Vistra's mindset around safety is exemplified by our motto: Best Defense. Everyone wins. No one gets hurt. Our safety
culture revolves around people and human performance. We place a high importance on continuous improvement, along with a
keen focus on numerous learning and error-prevention tools. To facilitate a learning environment, our various operating plants
share their investigations and learnings of all safety events with all operations employees on weekly calls. The information is
presented by front-line employees and supported by management. The lessons from each event are shared across the fleet to
prevent similar incidents at other locations. All personnel at Vistra locations are encouraged to be actively involved in the safety
process. Managers are required to participate in safety engagements with staff to enable constant communication and sustained
interaction. In 2024, the generation fleet conducted more than 51,000 leadership safety engagements across the fleet continuing
our employee driven safety program focused on engagement of all employees.
Our focus on reducing the severity of injuries for both our employees and contractors who work with us has shown
positive results. Since the implementation of our Best Defense safety program, the number of serious injuries or fatalities has
decreased significantly. Although we do not focus on recordable incidents, our Total Recordable Incident rate (TRIR) for
company employees was 0.72, in the top quartile as compared to the Edison Electric Institute (EEI) 2023 Total Company Injury
Data for companies of comparable size. We encourage near-miss reporting and review of events to promote a learning
environment. In 2024, safety learning calls were held every week where near-miss and safety events were reviewed by our
operating teams to promote learning across the fleet.
All Vistra employees are covered by our safety program. Corporate and retail employees are required to complete periodic
training on safety topics through our online learning management system. Employees who are located at a power plant are
required to complete trainings based on job function, which is also tracked through our central learning management system. In
addition, the Company engages an independent third-party conformity assessment and certification vendor to manage adherence
to our safety standards for all vendors and contractors who work at our plants. In addition, we work closely with our suppliers
and contractors to ensure our safety practices are upheld.
All of our power plant facilities have effective health and safety programs and comply with OSHA regulations. In addition
to compliance, our generation fleet has a total of 14 plants that have been awarded the Voluntary Protection Program (VPP)
Star designation by the OSHA for superior demonstration of effective safety and health management systems and for
maintaining injury and illness rates below the national averages for our industry. Our Casco Bay, Forney, Lamar, and Liberty
generation facilities completed reevaluations and were recommended to continue as VPP Star in 2024. VPP Star status is the
highest designation of OSHA's Voluntary Protection Programs. The achievement recognizes employers and workers who have
implemented effective safety and health management systems and maintain injury and illness rates below national Bureau of
Labor Statistics (BLS) averages for their respective industries. These sites are self-sufficient in their ability to control workplace
hazards and are reevaluated every three to five years. Additionally, 32 of our power plants and mine locations have adopted a
proactive Behavior Based Safety approach to safety which focuses on identifying and providing feedback on at-risk behaviors
observed.
7

Our People
We recognize the value of having an inclusive workforce. Our employees reflect the communities we serve, ranging in
age, gender, ethnicity, physical appearance, thoughts, styles, religions, nationality, education and numerous other traits.
Creating and maintaining an environment where our employees feel appreciated for their talent and contribution enhances our
ability to recruit and retain the best talent in the marketplace and to provide a work environment that allows all employees to
continue to be their best.
Vistra is active in our communities through employee-led initiatives, business teams, and collaborations with many
community agencies, such as United Way. Another way we engage with our communities is through our supply chain initiative,
which seeks to create a dynamic supply chain that identifies suppliers of all sizes and across our markets that are able to provide
quality products and services to the business.
Training and Development
We believe the development of employees at all levels is critical to Vistra's current and future success. We have launched
key programs to develop leaders at all levels of the organization. Vistra's Essentials of Leadership provides new managers with
skills to lead organizations in situational leadership, business acumen, and exposes them to best practices from across the
company. We continue to evaluate and refine our programs as the development needs of our employees change. In 2024, Vistra
began including the former Energy Harbor employees and leaders in leadership and front-line training programs to accelerate
the integration of Vistra's culture with the new nuclear sites.
Vistra also provides many other training and development programs to help grow and develop employees at every level,
including online learning platform courses, learning management system courses, recorded webinars and presentations, self-
paced development and employee-specific skill training. The Vistra Learning Community is our online platform that
strategically supports employees in completing thousands of hours of professional training to support continuing education
requirements for their respective professional licenses, including accounting, legal and nuclear. In 2024, Vistra continued its
formal mentoring program available to all employees to focus on topics like organizational knowledge, career development,
individual development, collaboration and leadership. Over 450 employees participated in 2024. In 2024, Vistra launched
physical and online Career Hubs, where employees can go to learn about a wide variety of careers within the company and
identify skills they need to develop to pursue those roles. In addition, all full-time employees, other than those in a collective
bargaining unit, receive a formal performance review guiding development and improving results of the business.
Employee Benefits
Maintaining attractive benefits and pay are important for recruiting and retaining talent. We are committed to maintaining
an equitable compensation structure, including performing annual salary reviews by employee category level within significant
locations of operations. Eligible full- and part-time employees are provided access to medical, prescription drug, dental, vision,
life insurance, accidental death and dismemberment, long-term disability coverage, accident coverage, critical illness coverage
and hospital indemnity coverage. Regular full-time employees are eligible for short-term disability benefits, and all employees
are eligible for the employee assistance program, parental leave, maternity leave and a 401(k) plan through which the Company
matches employee contributions up to 6%.
Wellness
We believe a healthy workforce leads to greater well-being at work and at home. To help keep our workforce healthy, we
offer access to on-site medical clinics at six locations. Our healthcare plans are also designed to reward employees for getting
annual physicals, age and gender health screenings and immunizations. In addition, our employee medical plans promote
mental health and emotional wellness and offer resources for employees seeking assistance. Fitness centers in multiple facilities
offer cardio equipment, a selection of free weights and exercise mats. Our employee-led wellness team engages our people to
get active and support causes that promote healthy living. With support from the company, the wellness team covers the
registration costs for employees to participate in running and cycling events throughout the year.
8

Environmental Regulations and Related Considerations
We are subject to extensive environmental regulation by governmental authorities, including the EPA and the
environmental regulatory bodies of states in which we operate. The EPA has finalized or proposed several regulatory actions
establishing new requirements for control of certain emissions from sources, including electricity generation facilities.
However, in January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American
Energy (the Order) that ordered that all federal agencies are to review all existing regulations, orders, and other actions for
consistency with the policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies. The Order
requires the EPA to review the GHG, CSAPR, Legacy CCR and ELG rules discussed below. Additionally, the Order states the
U.S. Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews. See Item
1A. Risk Factors and Note 15 to the Financial Statements for additional information.
Climate Change
There is continuing interest from our stakeholders domestically and internationally on global climate change and how
GHG emissions, such as CO2, contribute to global climate change. GHG emissions from the combustion of fossil fuels,
primarily by our coal-fueled-generation plants as well as our natural gas-fueled generation plants represent the substantial
majority of our total GHG emissions. CO2, methane and nitrous oxide are emitted in this combustion process, with CO2
representing the largest portion of these GHG emissions. We estimate that our generation facilities produced approximately 95
million short tons of CO2 in the year ended 2024. Vistra's carbon intensity for power generation improved from 0.56 short tons
of CO2 per MWh in 2023 to 0.48 short tons of CO2 per MWh in 2024, a 15% year-over-year improvement driven by our
Energy Harbor acquisition.
To manage our environmental impact from our business activities and reduce our emissions profile, Vistra set emissions
reduction targets. Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO2 equivalent emissions by 2030 as
compared to a 2010 baseline with a long-term goal to achieve net-zero carbon emissions by 2050, assuming necessary
advancements in technology and supportive market constructs and public policy. Since 2010, Vistra has retired more than
15,100 MW of coal and natural gas power plants resulting in a 50% reduction in carbon dioxide (CO2) emissions, a 66%
reduction in nitrogen oxide (NOX) emissions, and an 90% reduction in sulfur dioxide (SO2) emissions through year-end 2024,
compared to a 2010 baseline. Vistra also has targets validated through the Science Based Targets initiative (SBTi). Our near-
term science-based targets are to reduce absolute scope 1 and 2 GHG emissions 58% by 2028 from a 2018 base year, reduce
absolute scope 1 and 3 GHG emissions from all sold electricity 58% within the same timeframe, and reduce absolute scope 3
GHG emissions from use of sold products 42% within the same timeframe. Vistra is exploring multiple options to meet these
targets, but we must balance these efforts with the need to prioritize reliability and affordability for our customers.
The evolution of our generation portfolio is focused on ensuring reliability and affordability in the markets we serve with
an emphasis on resilient dispatchable assets complemented by zero-carbon assets. We seek to serve our customers through a
variety of generation sources, including efficient natural gas units, nuclear generation, renewables, and battery ESS, while we
also continuously explore new technologies with lower carbon footprints.
We have already taken or announced significant steps to transform our generation portfolio with the goal of maintaining
reliability while also reducing the emissions intensity of our generation fleet, including:
•
Acquisition of Nuclear Generation Facilities — In 2024, we acquired 4,048 MW of nuclear generation facilities in
PJM from Energy Harbor.
•
Re-powered generation assets — In May 2024, we announced our intention to repower the coal-fueled Coleto Creek
Power Plant near Goliad, Texas as a natural-gas fueled plant with up to 600 MW of capacity.
•
Uprated capacity at existing natural gas plants — Additional capacity has been added to existing natural gas plants
through technological upgrades improving efficiency and overall fleet intensity.
•
Battery Energy Storage Projects — As of December 31, 2024, we owned battery ESS totaling 750 MW in California,
270 MW in Texas and 4 MW in Illinois. We have announced our plans to develop additional battery ESS at retired or
to-be-retired plant sites in Illinois.
•
Solar Projects — As of December 31, 2024, we owned solar generations facilities totaling 338 MW in Texas and 112
MW in Illinois. We have announced our plans to develop additional solar generation facilities in Texas, with expected
commercial operation dates beginning in 2025, and additional solar generation facilities at retired or to-be retired
plant sites in Illinois with expected commercial operation dates beginning in 2026.
We will only invest in growth projects if we are confident in the expected returns.
9

Green Finance Framework
In December 2021, we announced the publication of our Green Finance Framework, which allows us to issue green
financial instruments to fund new or existing projects that support renewable energy and energy efficiency with alignment to
our ESG strategy.
Greenhouse Gas Emissions (GHG)
In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the
Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final
GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-,
oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and
sequestration/storage (CCS) and natural gas co-firing. Starting in 2030, the rule would begin to require more CO2 emissions
control at certain existing fossil fuel-fired steam generating units, with more stringent standards beginning in 2032 for coal-fired
units that plan to operate for a longer period of time. For new natural gas combustion turbines that operate more frequently, the
rule would phase in increasingly stringent CO2 requirements over time. Under the rule, states would be required to submit plans
to the EPA within 24 months of the rule's publication in the Federal Register that provide for the establishment,
implementation, and enforcement of standards of performance for existing sources. These state plans must generally establish
standards that are at least as stringent as the EPA's emission guidelines. Under the rule, existing coal-fired steam generation
units that will operate on or after January 1, 2039 must start complying with their standards of performance (based on
application of CCS with 90 percent capture) by January 1, 2032. Units that are permanently retiring before January 1, 2039, but
after December 31, 2031, must start complying with their standards of performance (based on co-firing with 40 percent natural
gas on a heat input basis) beginning on January 1, 2030. Units permanently retiring by January 1, 2032 are exempt from the
rule. Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only
coal units that are subject to this rule. Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also
regulated under this rule. None of our existing large or small combustion turbines are subject to this rule. The rule also regulates
any new gas units. For new combustion turbine units, the rule establishes three different categories depending on how
intensively those units are operated, with immediate compliance obligations for all three categories but more stringent standards
beginning in 2032 only for the category of units operating the most intensively. Following finalization of the rule in May 2024,
17 petitions for review from various states, industry groups and companies were filed in the D.C. Circuit Court along with
multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. In July 2024, the D.C.
Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S.
Supreme Court to stay the rule which was denied in October 2024. Oral argument on the merits of the legal challenges to the
rule was held in December 2024 before the D.C. Circuit Court. In February 2025, the D.C. Circuit granted the unopposed
motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while
the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.
State Regulation of GHGs
Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only
regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change.
Regional Greenhouse Gas Initiative (RGGI) — RGGI is a state-driven GHG emission control program that took effect in
2009 and was initially implemented by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants.
The participating RGGI states implemented a cap-and-trade program. Compliance with RGGI can be achieved by reducing
emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. We are required to
hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period.
In December 2017, the RGGI states released an updated model rule with changes to the CO2 budget trading program,
including an additional 30 percent reduction in the CO2 annual cap by the year 2030, relative to 2020 levels. RGGI is currently
conducting its third program review which may include an updated model rule.
Our generation facilities in Connecticut, Maine, Massachusetts, New Jersey, New York and Virginia emitted
approximately 11 million short tons of CO2 during 2024. The spot market price of RGGI allowances required to operate these
facilities as of December 31, 2024 was approximately $24.13 per allowance. While the cost of allowances required to operate
our RGGI-affected facilities is expected to increase in future years, we expect that the cost of compliance would be reflected in
the power market, and the actual impact to gross margin would be largely offset by an increase in revenue.
10

Massachusetts — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final
rules establishing an annual declining limit on aggregate CO2 emissions from 21 in-state fossil-fueled electricity generation
units. The rules establish an allowance trading system under which the annual aggregate electricity generation unit sector cap on
CO2 emissions declines from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. MassDEP allocated emission
allowances to affected facilities for 2018. Beginning in 2019, the allocation process transitioned to a competitive auction
process whereby allowances are partially distributed through a competitive auction process and partially distributed based on
the process and schedule established by the rule. Beginning in 2021, all allowances were distributed through the auction.
Limited banking of unused allowances is allowed.
Virginia — In May 2019, the Virginia Department of Environmental Quality issued a final rule to adopt a carbon cap-and
trade program for fossil-fueled electricity generation units, including our Hopewell facility, beginning in 2020. The program is
based on the RGGI proposed 2017 model rule and linked Virginia to RGGI in 2021. The Governor of Virginia issued an
executive order in January 2022 to begin the process of removing the state from RGGI. The Virginia State Pollution Control
Board withdrew the state from RGGI at the end of 2023, coinciding with the end of the program's three-year compliance period
and contract with RGGI, Inc. In August 2023, opponents of the state's action filed suit seeking a stay alleging withdrawal from
RGGI is impermissible without new legislation. In November 2024, a state circuit court judge ruled that the removal of Virginia
from RGGI was unlawful, but the state has moved to stay the circuit court's judgment. Virginia is not participating in RGGI at
this time.
New Jersey — In January 2018, the Governor of New Jersey signed an executive order directing the state's environmental
agency and public utilities board to begin the process of rejoining RGGI, and New Jersey formally rejoined RGGI in June 2019.
In June 2019, New Jersey adopted two rules that govern New Jersey's reentry into the RGGI auction and distribution of the
RGGI auction proceeds.
Pennsylvania — In April 2022, the Pennsylvania Environmental Quality Board finalized regulations that would establish
Pennsylvania's participation in RGGI. In July 2022, the Commonwealth Court of Pennsylvania (Commonwealth Court) took
action to uphold a preliminary injunction over Pennsylvania's RGGI regulations. The Pennsylvania Supreme Court denied a
request for emergency relief from the injunction in August 2022. In November 2023, the Commonwealth Court found that
Pennsylvania cannot join RGGI without legislative approval and enjoined the Pennsylvania Department of Environmental
Protection from implementing RGGI. The state has appealed this decision to the Pennsylvania Supreme Court where it is still
pending. The Pennsylvania Department of Environmental Protections has indicated it will not seek to implement RGGI until the
Pennsylvania Supreme Court acts. As a result, RGGI is not being implemented or enforced in Pennsylvania at this time.
California — Our assets in California are subject to the California Global Warming Solutions Act, which required the
California Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state
to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establishing a new statewide GHG
reduction target of 40 percent below 1990 levels by 2030 to ensure California meets its 2050 GHG reduction target of 80
percent below 1990 levels. We have participated in quarterly auctions or in secondary markets, as appropriate, to secure
allowances for our affected assets.
In July 2017, California enacted legislation extending its GHG cap-and-trade program through 2030 and the CARB
adopted amendments to its cap-and-trade regulations that, among other things, established a framework for extending the
program beyond 2020 and linking the program to the new cap-and-trade program in Ontario, Canada beginning in January
2018.
Air Emissions
The Clean Air Act (CAA)
The CAA and comparable state laws and regulations relating to air emissions impose various responsibilities on owners
and operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit
fees, monitor emissions, submit reports and compliance certifications, and keep records. The CAA requires that fossil-fueled
electricity generation plants meet certain pollutant emission standards and have sufficient emission allowances to cover SO2
emissions and in some regions NOX emissions.
11

In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission
reduction technologies. These technologies include flue gas desulfurization (FGD) systems, dry sorbent injection (DSI),
baghouses and activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective
catalytic reduction (SCR) systems, low-NOX burners and/or overfire air systems on all units.
Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan
In 2016, the EPA finalized the Cross-State Air Pollution Rule Update (CSAPR Update) to address 22 states' obligations
with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). In 2019, following challenges by numerous
parties, the D.C. Circuit Court found that the CSAPR Update did not fully address certain states' 2008 ozone NAAQS
obligations. In October 2020, the EPA proposed an action to address the outstanding 2008 ozone NAAQS obligations in
response to the D.C. Circuit Court's 2019 ruling. Vistra subsidiaries filed comments on that rulemaking in December 2020, and
the EPA published a final rule in the Federal Register on April 30, 2021 that reduces ozone season NOX budgets in certain
states. We do not believe that the final rule causes a material adverse impact on our future financial results.
In October 2015, the EPA revised the primary and secondary ozone NAAQS to lower the 8-hour standard for ozone
emissions during ozone season (May to September). As required under the CAA, in October 2018, the State of Texas submitted
a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly
to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS. In February
2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that
disapproval in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). In March 2023, those same parties filed
motions to stay the EPA's SIP disapproval in the Fifth Circuit Court, and the EPA moved to transfer our challenges to the D.C.
Circuit Court or have those challenges dismissed.
In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to
address the 2015 ozone NAAQS. We, along with many other companies, trade groups, states and ISOs, including ERCOT, PJM
and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the
proposal, particularly those that may result in challenges to electric reliability under certain conditions. In March 2023, the EPA
administrator signed its final FIP, called the Good Neighbor Plan (GNP). The FIP applied to 22 states beginning with the 2023
ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New
York, Ohio, Pennsylvania, Texas, Virginia, and West Virginia. Texas would be moved into the revised (and more restrictive)
Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets for 2023
that the EPA says are achievable through existing controls installed at power plants. Allowances will be limited under the
program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of coal-
fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic
reduction systems such as our Martin Lake power plant.
In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision
on the merits and denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. As a result of the stay, we do not
believe the EPA has authority to implement the GNP FIP as to Texas sources pending the resolution of the merits, meaning that
Texas will remain in Group 2 and not be subject to any requirements under the GNP FIP at least until the Fifth Circuit Court
rules on the merits. Oral argument was heard in December 2023 before the Fifth Circuit Court. In June 2023, the EPA published
the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the
Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the GNP FIP in
the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the
motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the GNP
FIP as to Texas is stayed. In February 2025, the Department of Justice filed a motion on behalf of the EPA in the Fifth Circuit
Court, seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it
wishes to proceed. In February 2025, the State of Texas filed a response opposing the requested abatement, which we joined. In
July 2023, the Fifth Circuit Court ruled that the GNP FIP challenge would be held in abeyance pending the resolution of the
litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay. In a related
action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S. Supreme Court granted a stay of the
GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a
result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP. In February 2025, the
D.C. Circuit Court denied a motion filed by the Department of Justice on behalf of the EPA, seeking to hold the litigation in
abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to
proceed.
12

Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas
The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of
any existing, impairment of visibility in mandatory class I federal areas which impairment results from man-made pollution."
There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I
federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in
neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second,
certain electricity generation units built between 1962 and 1977 are subject to BART standards designed to improve visibility if
such units cause or contribute to impairment of visibility in a federal class I area.
In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving
as a partial approval of Texas' 2009 SIP and a partial FIP. For SO2, the rule established an intrastate Texas emission allowance
trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes
39 generation units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2, and Graham 2
plants). The compliance obligations in the program started on January 1, 2019. For NOX, the rule adopted the CSAPR's ozone
program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity generation units
are subject to BART for particulate matter. In August 2020, the EPA issued a final rule affirming the prior BART final rule but
also included additional revisions that were proposed in November 2019. Challenges to both the 2017 rule and the 2020 rules
have been consolidated in the D.C. Circuit Court, where we have intervened in support of the EPA. We are in compliance with
the rule, and the retirements of our Monticello, Big Brown, and Sandow 4 plants have enhanced our ability to comply. The EPA
is in the process of reconsidering the BART rule, and the challenges in the D.C. Circuit Court have been held in abeyance
pending the EPA's final action on reconsideration. In May 2023, a proposed BART rule was published in the Federal Register
that would withdraw the trading program provisions of the prior rule and would establish SO2 limits on six facilities in Texas,
including Martin Lake and Coleto Creek. Under the current proposal, compliance would be required within 3 years for Martin
Lake and 5 years for Coleto Creek. Due to the announced shutdown for Coleto Creek, we do not anticipate any impacts at that
facility, and we are evaluating potential compliance options at Martin Lake should this proposal become final. We submitted
comments to the EPA on this proposal in August 2023.
National Ambient Air Quality Standards (NAAQS)
The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment.
The EPA has established NAAQS for six such pollutants, including SO2 and ozone. Each state is responsible for developing a
SIP that will attain and maintain the NAAQS. These plans may result in the imposition of emission limits on our facilities.
13

SO2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation
plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment
plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in
the Fifth Circuit Court. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized,
would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable. In May
2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants,
redesignating those areas as attainment based on monitoring data supporting an attainment designation. In June 2021, the EPA
published two notices; one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice
denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations. We, along with
the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court,
and this case was argued before the Fifth Circuit Court in July 2022. In September 2021, the TCEQ considered a proposal for
its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO2 emissions from the plant. The
proposed agreed order associated with the SIP proposal reduced emission limits as of January 2022. Emission reductions
required are those necessary to demonstrate attainment with the NAAQS. The TCEQ's SIP action was finalized in February
2022 and has been submitted to the EPA for review and approval. In January 2024, in a split decision, the Fifth Circuit Court
denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO2 for the
area around Martin Lake. As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains
in place. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January
2024, which remains pending before the full Fifth Circuit Court. In August 2024, the EPA proposed a Finding of Failure to
attain the SO2 standard for Rusk and Panola Counties, a partial approval and partial disapproval of the Texas SIP and a
proposed federal plan for the area. In December 2024, the EPA finalized the Finding of Failure to attain the standard and stated
that it would take final action of the SIP partial approval and disapproval in a future action. In February 2025, we, along with
the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court.
Ozone Designations
The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. Areas
surrounding our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facility in Illinois and our Wise, Ennis
and Midlothian facilities in Texas were designated marginal nonattainment areas in June 2018 by the EPA with an attainment
deadline of August 2021. In June 2022, the areas surrounding our Ohio Dicks Creek and Miami Fort facilities were
redesignated "attainment." The EPA redesignated the area around our Texas Wise, Ennis and Midlothian facilities to
"moderate" in October 2022 and again "bumped up" the classification to serious in June 2024. Middlesex County in New
Jersey, where our Sayreville facility is located, was designated a "moderate" nonattainment area. In July 2024, the state of New
Jersey, in collaboration with the states of New York and Connecticut requested a voluntary bump up of the New York-Northern
New Jersey-Long Island nonattainment area, which includes Middlesex County where our Sayreville facility is located. States
will be required to develop SIPs to address emissions in areas with a higher (more stringent) classification.
Particulate Matter
In February 2024, the EPA issued a rule addressing the annual health-based national ambient air quality standards for fine
particulate matter (or PM2.5). In general, the rule lowers the level of the annual PM2.5 standard from 12.0 micrograms per
cubic meter (µg/m3) to 9.0 µg/m3. The effective date of the rule is 60 days from publication in the Federal Register, and the
earliest attainment date for areas exceeding the new standard is 2032. Based on 2021-2023 design value associated with the
rule, we have just four plants (Calumet (Illinois), Dicks Creek and Miami Fort (Ohio), and Lake Hubbard (Texas)) operating in
areas where the air quality monitoring data are currently exceeding the new PM2.5 standard. We have previously announced
that our Miami Fort generation facility will close by the end of 2027. States will have to develop a plan (by late 2027 at the
earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those
sites. However, before the state begins this planning process, the designation process will occur within two years from the
issuance of the final rule. The states develop recommendations about the boundaries of the nonattainment counties and the EPA
must finalize the designations including the boundaries of each nonattainment area.
Coal Combustion Residuals (CCR)/Groundwater
The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at
power generation facilities in dry form in landfills and in wet form in surface impoundments. Each of our coal-fueled plants has
at least one CCR surface impoundment.
14

CCR Rule Revisions and Extension Applications
The EPA's CCR rule, which took effect in October 2015, establishes minimum federal requirements for the construction,
retrofitting, operation and closure of, and corrective action with respect to, existing and new CCR landfills and surface
impoundments, as well as inactive CCR surface impoundments. The requirements include location restrictions, structural
integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping
and notification. The deadlines for beginning and completing closure vary depending on several factors. The Water
Infrastructure Improvements for the Nation Act (the WIIN Act), which was enacted in December 2016, provides for EPA
review and approval of state CCR permit programs.
In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR
rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a
deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The 2020 final rule
allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and
either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the
size of the impoundment at issue).
Prior to the November 2020 deadline to seek extensions, we submitted applications to the EPA requesting compliance
extensions under both conversion and retirement scenarios. In January 2022, the EPA determined that our conversion and
retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications.
In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported
to impose new, more onerous closure requirements for CCR units. In April 2022, we, along with the Utility Solid Waste
Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other
industry associations, filed petitions for review with the D.C. Circuit Court and asked the court to determine that the EPA
cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures. The
State of Texas and the TCEQ intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various
environmental groups have intervened on behalf of the EPA. In June 2024, the D.C. Circuit Court dismissed the petitions filed
challenging the EPA's January 2022 statements because it found the statements did not amend the existing CCR regulations,
and thus the D.C. Circuit Court did not have jurisdiction to review them.
Legacy CCR Rulemaking
In May 2024, the EPA published a final rule that expands coverage of groundwater monitoring and closure requirements
to the following two new categories of units: (a) legacy CCR surface impoundments which are CCR surface impoundments that
no longer receive CCR but contained both CCR and liquids on or after October 19, 2015 and (b) "CCR management
units" (CCRMUs) which generally could encompass noncontainerized ash deposits greater than one ton and impoundments and
landfills that closed prior to October 19, 2015. As part of the rule, the EPA identified numerous CCR management units across
the country, including ten of our potential units. The Vermilion ash ponds discussed below are the only unit which we believe
qualify as a legacy CCR surface impoundment and given our closure plan for that site we do not believe the rule will have any
impact on that site. CCRMUs with 1,000 or more tons of CCR must comply with the CCR's groundwater monitoring, corrective
action, closure and post-closure requirements. For CCRMUs, complete facility evaluation reports are due within 33 months
after publication of the rule, initial groundwater reports are due January 31, 2029, and the deadline to initiate closure, if needed,
will start in 2029. Closure of the CCRMUs may also be deferred beyond those dates depending on certain factors, including
where the CCRMU is located beneath critical infrastructure. In addition, certain closures may not be required when closure was
previously approved under a state program. Because facility evaluation reports will determine our unit-specific compliance
obligations, we cannot determine them at this time. In August 2024, we, along with USWAG, several other generating
companies, and 17 states, including Texas, filed a challenge to the rule in the D.C. Circuit Court. In February 2025, the D.C.
Circuit Court granted an unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in
abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to
proceed.
MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of
groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices
remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east,
and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility.
15

At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned
D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR
surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in
2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion
surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing
options. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface
impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the
Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a
complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation
notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic
river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim
consent order, DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation
(discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment
closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if
necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the
impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency
Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms
above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and
submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash.
These proposed closure costs are reflected in the ARO in the consolidated balance sheets (see Note 13 to the Financial
Statements).
In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen
facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal
CCR rule.
In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements
for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of
guidelines, rules, and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became
effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA
for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal
at any site. In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over
certain provisions of the final rule. In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry
petitions. We do not anticipate any impacts from this decision. In October 2021, we filed operating permit applications for 18
impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in
January 2022 and five of our sites in July 2022. One additional closure construction application was filed for our Baldwin
facility in August 2023.
For all of the above CCR matters, if certain corrective action measures, including groundwater treatment or removal of
ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on
our financial condition, results of operations, and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not
require removal. However, the rule required us to undertake further site-specific evaluations required by each program. We will
not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required
under the Illinois rule until permit applications have been approved by the IEPA and as such, an estimate of such costs cannot
be made. The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the
costs of closure methods that our operations and environmental services teams determined were appropriate based on the
existing closure requirements at the time we recorded those ARO liabilities, and is reasonably possible for those to increase
once the IEPA determines final closure requirements. Once the IEPA acts on our permit applications, we will reassess the
decommissioning costs and adjust our ARO liabilities accordingly.
Water
The EPA and the environmental regulatory bodies of states in which we operate have jurisdiction over the diversion,
impoundment and withdrawal of water for cooling and other purposes and the discharge of wastewater (including storm water)
from our facilities. We believe our facilities are presently in material compliance with applicable federal and state requirements
relating to these activities. We believe we hold all required permits relating to these activities for facilities in operation and have
applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements
necessary to obtain any required permits or renewals.
16

Effluent Limitation Guidelines (ELGs) — In November 2015, the EPA revised the ELGs for steam electricity generation
facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as FGD,
fly ash, bottom ash, and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and
the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of
the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated
and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA
published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later
than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement
exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are
met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a
motion to intervene in support of the EPA in December 2020. Notifications were made to Texas, Illinois, and Ohio state
agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In May 2024,
the EPA published the final ELG rule revisions, which contain new requirements for legacy wastewater and combustion
residual leachate. The final rule also leaves in place the subcategory for facilities that permanently cease coal combustion by
2028. We are reviewing the rule for impact but believe it will require additional treatment costs for legacy wastewaters during
pond closure activities and combustion residual leachate. At this time, we don't expect the impact of these additional treatment
costs to be material. A number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals
for the Eighth Circuit. We are not a party to that litigation. In February 2025, the Department of Justice on behalf of the EPA
filed an unopposed motion seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and
determines how it wishes to proceed.
Radioactive Waste
The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily using
dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the U.S.
Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear
fuel storage capability is sufficient for the foreseeable future.
Corporate Information
Vistra is a Delaware corporation whose common stock is listed and traded on the NYSE. Our principal executive office is
located at 6555 Sierra Drive, Irving, Texas 75039. The telephone number for our principal executive office is (214) 812-4600.
We maintain a website located at www.vistracorp.com.
Available Information
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any
amendments to those reports with the SEC. You may obtain copies of these documents, free of charge, on the SEC's website at
www.sec.gov or on Vistra's website at www.vistracorp.com, as soon as reasonably practicable after they have been filed with or
furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. Vistra also posts
important information, including press releases, investor presentations, sustainability reports, and notices of upcoming events
on its website and utilizes its website as a channel of distribution to reach public investors and as a means of disclosing material
non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings
to our website by signing up for email alerts and RSS feeds on the "Investor Relations" page. The information on Vistra's
website shall not be deemed a part of, or incorporated by reference into, this annual report on Form 10-K.
17

Item 1A. RISK FACTORS
Summary of Risk Factors
The following summarizes the principal factors that make an investment in our company speculative or risky, all of which
are more fully described in the Risk Factors section below. This summary should be read in conjunction with the Risk Factors
section and should not be relied upon as an exhaustive summary of the material risks facing our business. The following factors
could result in harm to our business, financial condition, results of operations, cash flows, and prospects, among other impacts:
Market, Financial, and Economic Risks
•
Our revenues, results of operations, and operating cash flows are affected by price fluctuations in the wholesale
power market and other market factors beyond our control.
•
We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel
costs or disruptions in these fuel markets may have an adverse impact on, our costs, revenues, results of operations,
financial condition, and cash flows.
•
We have retired, announced planned retirements of, and may be forced to retire or idle additional underperforming
generation units which could result in significant costs and have an adverse effect on our operating results.
•
Our assets or positions cannot be fully hedged against changes in commodity prices and Market Heat Rates, and
hedging transactions may not work as planned or hedge counterparties may default on their obligations.
•
Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power
markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of
operations, and cash flows.
•
Our results of operations and financial condition could be materially and adversely affected by energy market
participants continuing to construct new generation facilities or expanding or enhancing existing generation facilities
despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power
prices.
•
Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or
during times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable
terms or at all in the future, which could have a material adverse effect on us.
•
The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures,
contain restrictions and limitations that could affect our ability to operate our business, our liquidity, and our results
of operations, and any failure to comply with these restrictions could have a material adverse effect on us.
•
We may not be able to complete future acquisitions on favorable terms or at all, successfully integrate future
acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which
could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy.
•
Our ability to achieve the expected growth of our Vistra Zero portfolio, consisting of our solar generation, battery
ESS, and other renewables development projects, is subject to substantial capital requirements and other significant
uncertainties.
•
Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or
increased taxes or fees, could have a material adverse effect on our financial condition, results of operations, and cash
flows.
•
If electricity demand does not grow at the rate expected, or if we are unable to execute on large load offtake
opportunities, our financial performance, growth opportunities, and stock price could be adversely impacted.
Regulatory and Legislative Risks
•
Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely
impacted, and may in the future adversely impact, our businesses, results of operations, liquidity and financial
condition.
18

•
Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.
•
Pending or proposed laws or regulations, or the repeal of existing beneficial laws or regulations, including those
proposed or implemented under the Trump administration, could have a material adverse effect on our businesses,
results of operations, liquidity and financial condition.
•
Changes to laws, rules or regulations related to market structures in the markets in which we participate may have a
material adverse effect on our businesses, results of operation, liquidity and financial condition.
•
We could be materially and adversely affected if current regulations are implemented or if new federal or state
legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged
damage to persons or property resulting from greenhouse gas emissions.
•
Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to
significant liabilities and reputational damage that could have a material adverse effect on us.
Operational Risks
•
Volatile power supply costs and demand for power have and could in the future adversely affect the financial
performance of our retail businesses.
•
Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing
customers and the inability to attract new customers.
•
Cybersecurity attacks or technology systems failures could disrupt business operations and expose us to significant
liabilities, reputational damage, loss of customers, and regulatory action.
•
The operation of our businesses is subject to information security and operational technology risks, including
cybersecurity breaches and failure of critical information and operations technology systems. Attacks on our
infrastructure that breach cyber/data security measures could expose us to significant liabilities, reputational damage,
regulatory action, and disrupt business operations, which could have a material adverse effect on us.
•
We may suffer material losses, costs and liabilities due to operational risks, regulatory risks, and the risk of nuclear
accidents arising from the ownership and operation of the nuclear generation facilities.
•
The operation and maintenance of power generation facilities and related mining operations are capital intensive and
involve significant risks that could adversely affect our results of operations, liquidity and financial condition.
•
We may be materially and adversely affected by obligations to comply with federal and state regulations, laws, and
other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and
monitoring relating to CCR.
•
We have been and may in the future be materially and adversely affected by the effects of extreme weather conditions
and seasonality.
•
Events outside of our control, including an epidemic or outbreak of an infectious disease may materially adversely
affect our business.
•
Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the
value of our business, introduce new or emerging risks and may otherwise have a material adverse effect on us.
Risks Related to Our Structure and Ownership of our Common Stock
•
Evolving expectations from stakeholders, including investors, on ESG issues, including climate change and
sustainability matters, and erosion of stakeholder trust or confidence could influence actions or decisions about our
company and our industry and could adversely affect our business, operations, financial results, or stock price.
•
We may not pay any dividends on our common stock in the future, and we may not realize the anticipated benefits of
our share repurchase program.
19

Please carefully consider the following discussion of significant factors, events, and uncertainties that make an
investment in our securities risky. These factors, in addition to others specifically addressed in Item 7. Management's
Discussion and Analysis of Financial Condition, and Results of Operations (MD&A), provide important information for the
understanding of our forward-looking statements in this annual report on Form 10-K. If one or more of the factors, events and
uncertainties discussed below or in the MD&A were to materialize, our business, results of operations, liquidity, financial
condition, cash flows, reputation or prospects could be materially adversely affected. In addition, if one or more of such factors,
events and uncertainties were to materialize, it could cause results or outcomes to differ materially from those contained in or
implied by any forward-looking statement in this annual report on Form 10-K. There may be further risks and uncertainties that
are not currently known or that are not currently believed to be material that may adversely affect our business, results of
operations, liquidity, financial condition and prospects and the market price of our common stock in the future. The realization
of any of these factors could cause investors in our securities (including our common stock) to lose all or a substantial portion
of their investment.
Market, Financial and Economic Risks
Our revenues, results of operations and operating cash flows generally are affected by price fluctuations in the wholesale
power market and other market factors beyond our control.
We are not guaranteed any rate of return on capital investments in our businesses. We conduct integrated power
generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales
of electricity and natural gas to end users and commodity risk management. Our wholesale and retail businesses are to some
extent countercyclical in nature, particularly for the wholesale power and ancillary services supplied to the retail business.
However, we do have a wholesale power position that is subject to wholesale power price moves, which may be significant. As
a result, our revenues, results of operations and operating cash flows depend in large part upon wholesale market prices for
electricity, natural gas, uranium, lignite, coal, fuel oil, and transportation in our regional markets and other competitive markets
in which we operate and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of
regulatory authorities.
Market prices for power, capacity, ancillary services, natural gas, coal and fuel oil are unpredictable and may fluctuate
substantially over relatively short periods of time. Unlike most other commodities, electric power can only be stored on a very
limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant
volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Demand for electricity can
fluctuate dramatically, creating periods of substantial under- or over-supply. Over-supply can occur as a result of the
construction of new power generation sources. During periods of over-supply, electricity prices might be depressed. For
example, in many instances, energy from renewable resources, such as solar, wind and battery ESS, are bid into the relevant
spot market at a price of zero or close to zero during certain times of the day, lowering the clearing price for all power
wholesalers in such market. Also, at times there is political pressure, or pressure from regulatory authorities with jurisdiction
over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other
mechanisms to address volatility and other issues in these markets.
Extreme weather events can also materially impact power prices or otherwise exacerbate conditions or circumstances that
result in volatility of power prices. For example, in February 2021, the U.S. experienced Winter Storm Uri and extreme cold
temperatures in the central U.S., including Texas. This severe weather event substantially increased the demand for natural gas
used in our electric power generation business, and the cold further limited the availability of renewable generation across the
region contributing to extremely high market prices for natural gas and electricity, which resulted in substantial increases in the
costs to procure sufficient fuel supply and increased collateral posting requirements. Winter Storm Elliott, in December 2022,
and Winter Storm Heather, in January 2024, were other examples of extreme weather across the U.S. that resulted in
widespread wholesale power market volatility.
The majority of our facilities operate as "merchant" facilities without long-term power sales agreements. As a result, we
largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and
retail power markets on a short-term basis and are not guaranteed any rate of return on our capital investments. Consequently,
there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those
facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon
prevailing market prices for power, capacity and fuel. Given the volatility of commodity power prices, to the extent we are
unable to hedge or otherwise secure long-term power sales agreements for the output of our power generation facilities, our
revenues and profitability will be subject to volatility, and our financial condition, results of operations and cash flows could be
materially adversely affected.
20

We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel costs,
volatility, or disruption in these fuel markets may have an adverse impact on our costs, revenues, results of operations,
financial condition and cash flows.
We rely on natural gas, coal, fuel oil, and nuclear fuel for the majority of our power generation facilities. Delivery of these
fuels to the facilities is dependent upon the continuing availability of such fuels and financial viability of contractual
counterparties as well as upon the infrastructure (including mines, rail lines, rail cars, barge facilities, roadways, riverways and
natural gas pipelines) available and functioning to serve each generation facility, and geopolitical risk, including the current
Russia and Ukraine conflict and the potential for additional U.S. sanctions against Russia or other potential restrictions on
Russian energy deliveries. See Item 7. Management's Discussion and Analysis of Financial Condition, and Results of
Operations – Significant Activities and Events, and Items Influencing Future Performance - Macroeconomic Conditions. As a
result, we have experienced, and remain subject to the risks of disruptions or curtailments in the production of power at our
generation facilities if no fuel is available at any price, if a counterparty fails to perform or if there is a disruption in the fuel
delivery infrastructure. Certain of our generation facilities rely on a limited number of counterparties, such as natural gas
suppliers and railcar companies, to provide the necessary fuel. Disputes relating to or non-performance of contractual
arrangements have resulted in, and may continue to result in adverse impacts to our costs, revenues, results of operations,
financial condition, and cash flows.
As part of our strategy to mitigate the potential negative effects of commodity price volatility, we have sold forward a
substantial portion of our expected power sales in the next few years in order to lock in long-term prices. In order to hedge our
obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase
and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or
discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel
supplier or transporter. Fuel costs (including diesel, natural gas, lignite, coal and nuclear fuel) are volatile, and the wholesale
price for power does not always change at the same rate as changes in fuel costs, and disruptions in our fuel supplies may
therefore require us to find alternative fuel sources at costs which may be higher than planned, to find other sources of power to
deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Long-
term and short-term contracts are subject to risk of non-delivery or claims of force majeure, which may impact our ability to
economically recover the value of the contract. In addition, we purchase and sell natural gas and other energy related
commodities, and volatility in these markets may affect costs incurred in meeting our obligations. Further, any changes in the
costs of natural gas, coal, fuel oil, nuclear fuel or transportation rates and changes in the relationship between such costs and the
market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we
consider favorable, or if we are unable to procure these fuels at all, our financial condition, results of operations and cash flows
could be materially adversely affected. For example, supply challenges were among the primary drivers of the significant loss
experienced in 2021 as a result of Winter Storm Uri.
We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate,
sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of energy
may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse
effect on our financial and operating performance. Volatility in market prices for fuel and power results from, among other
factors:
•
demand for energy commodities and general economic conditions, including impacts of inflation and the relative
strength or weakness of U.S. dollar compared to other currencies;
•
volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and fuel
oil;
•
volatility in Market Heat Rates;
•
volatility in coal and rail transportation prices;
•
volatility in nuclear fuel and related enrichment and conversion services;
•
transmission or transportation disruptions, constraints, congestion, inoperability or inefficiencies of electricity, natural
gas or coal transmission or transportation, or other changes in power transmission infrastructure;
•
severe, sustained or unexpected weather conditions, including extreme cold, drought and limitations on access to
water;
•
seasonality;
•
changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;
•
illiquidity in the wholesale power or other commodity markets;
•
importation of liquified natural gas to certain markets;
•
development and availability of new fuels, new technologies and new forms of competition for the production and
storage of power, including competitively priced alternative energy sources or storage;
21

•
changes in market structure and liquidity;
•
changes in the way we operate our facilities, including curtailed operation due to market pricing, environmental
regulations and legislation, safety or other factors;
•
changes in generation capacity or efficiency;
•
outages or otherwise reduced output from our generation facilities or those of our competitors;
•
changes in electric capacity, including the addition of new supplies of power as a result of the development of new
plants, expansion of existing plants, the continued operation of uneconomic power plants due to federal, state or local
subsidies, or additional transmission capacity;
•
local, regional, national, or global supply chain constraints or shortages;
•
our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
•
changes in the credit risk, payment practices, or financial condition of market participants;
•
changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;
•
pandemics and epidemics (including the impacts thereto, or recovery therefrom), natural disasters, wars, sabotage,
terrorist acts, embargoes and other catastrophic events; and
•
changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and
legislation.
See "Economic downturns would likely have a material adverse effect on our businesses" for a discussion of potential
risks arising from current U.S. and global economic and geopolitical conditions.
We have retired, announced planned retirements of, and may be forced to retire or idle additional underperforming
generation units which could result in significant costs and have an adverse effect on our operating results.
A sustained decrease in the financial results from, or the value of, our generation units has resulted in the retirement or
planned retirement of, and ultimately could result in additional retirements or idling of, generation units. We have operated
certain of our lignite- and coal-fueled generation assets only during parts of the year that have higher electricity demand and,
therefore, higher related wholesale electricity prices. In connection with the closure and remediation of retired generation units,
we have spent, and may in the future spend, a significant amount of money, internal resources and time to complete the required
closure and reclamation, which could have a material adverse effect on our financial and operating performance.
Our assets or positions cannot be fully hedged against changes in commodity prices and Market Heat Rates, and hedging
transactions may not work as planned, or counterparties may default on their obligations, which could have a material
adverse impact on our business, financial condition, results of operations and cash flows.
Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notably
electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative
to the duration of available markets for various hedging activities. Generally, commodity markets that we participate in to
hedge our exposure to electricity prices and Market Heat Rates have limited liquidity after two to three years. Further, our
ability to hedge our revenues by utilizing cross-commodity hedging strategies with natural gas hedging instruments is generally
limited to a duration of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or
Market Heat Rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favorably
or unfavorably.
22

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge
portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium
and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we
routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in
over-the-counter markets or on exchanges. Given our exposure to risks of commodity price movements, we devote a
considerable amount of time and effort to the establishment of risk management policies and procedures, as well as the ongoing
review of the implementation of these policies and procedures. Additionally, we have processes and controls in place that are
designed to monitor and accurately report hedging activities and positions. The policies, procedures, processes and controls in
place may not always function as planned and cannot eliminate all the risks associated with these activities, including
unauthorized hedging activity, or improper reporting thereof, by our employees in violation of our existing risk management
policies and procedures. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected
changes due to weather, natural disasters, consumer behavior, market constraints or other factors could cause us to purchase
electricity to meet unexpected demand in periods of high wholesale market prices or resell excess electricity into the wholesale
market in periods of low prices. As a result of these and other factors, the impacts of our commodity hedging activities and risk
management decisions may have a material adverse effect on our business, financial condition, results of operations and cash
flows.
Based on economic and other considerations, including our available liquidity, we may not be able to, or we may decide
not to, hedge the entire exposure of our operations to commodity price risk. To the extent we do not hedge against commodity
price risk and applicable commodity prices change in ways adverse to us, we could be materially and adversely affected. To the
extent we do hedge against commodity price risk, those hedges may ultimately prove to be ineffective. Additionally, there may
be changes to existing laws or regulations that could significantly impact our ability to effectively hedge, which may have a
material adverse effect on us.
To the extent we engage in hedging and risk management, and power purchase agreement activities, we are exposed to the
credit risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform
their obligations to us. Should the counterparties to these arrangements fail to perform, we could be forced to enter into
alternative hedging arrangements or honor the underlying commitment at then-current market prices. Additionally, our
counterparties may seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code.
Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient
to recover the full amount due to us. There can be no assurance that any such losses or impairments to the carrying value of our
financial assets would not materially and adversely affect our financial condition, results of operations and cash flows. In such
event, we could incur losses or forgo expected gains in addition to amounts, if any, already paid to the counterparties. Market
participants in the ISOs/RTOs in which we operate are also exposed to risks that another market participant may default on its
obligations to pay such ISO/RTO for electricity or services taken, in which case such costs, to the extent not offset by posted
security and other protections available to such ISO/RTO, may be allocated to various non-defaulting ISO/RTO market
participants, including us.
We do not apply hedge accounting to our commodity derivative transactions, which may cause increased volatility in our
quarterly and annual financial results.
We enter derivative instruments to manage commodity price risks. All our derivatives are accounted for as economic
hedges and are recorded at estimated fair value in the consolidated balance sheets with changes in fair value recorded as gains
or losses in the earnings of the period in which they occur. No derivative positions are accounted for as cash flow or fair value
hedges.
A derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or
delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under
the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract
until settlement. While certain retail sales contract portfolios are designated as normal, the majority of our derivative positions
are subject to adjustments caused by changes in forward commodity prices. As a result, our quarterly and annual financial
results, prepared in accordance with GAAP, are subject to increased volatility.
23

Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power markets,
together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and
cash flows.
Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale
marketplace may be undermined by changes in market structure and out-of-market subsidies provided by federal or state
entities, including bailouts of uneconomic plants, imports of power from Canada, renewable mandates or subsidies, as well as
out-of-market payments to new generators. Multiple potential changes have been and are being evaluated by the PUCT and the
Texas Legislature for the ERCOT market, including Dispatchable Reliability Reserve Service that would facilitate compliance
with a required reliability standard, the ultimate resolution of which is unknown. In another example, the resolution of a number
of filings pending at FERC could impact PJM capacity market rules in future years.
Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of
regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary
services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power
may be met by generation capacity based on several competing technologies, as well as power generation facilities fueled by
alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste
heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation increases
competition from these types of facilities and out-of-market subsidies to existing or new generation can undermine the
competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by us.
We also compete against other energy merchants on the basis of our relative operating skills, financial position and access
to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit
support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we
compete may have greater resources or experience in these areas. Over time, some of our plants may become unable to compete
because of subsidized generation, including public utility commission supported power purchase agreements, and the
construction of new plants. Such new plants could have a number of advantages including more efficient equipment and newer
technology that could result in fewer emissions or more advantageous locations on the electric transmission system.
Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer
technology utilized in their facilities or the additional resources derived from owning more efficient facilities.
Other factors may contribute to increased competition in wholesale power markets. We expect that we will continue to
face intense competition from numerous companies, including new entrants or consolidation of existing competitors, in the
industry. Certain federal and state entities in jurisdictions in which we operate have either enacted or are considering regulations
or legislation to subsidize otherwise uneconomic plants and attempt to incentivize, including through certain tax benefits, the
construction and development of additional renewable resources as well as increases in energy efficiency investments. For
example, the Inflation Reduction Act of 2022 contains a number of tax credits and incentives relating to renewable projects and
clean energy technologies such as nuclear energy. New entrants or existing competitors may find it more economical to develop
new renewable projects or invest in clean energy technologies in which we would like to invest. Subsidies (or increases thereto)
to our competitors could result in increased competition for us, which could have a material adverse effect on our financial
condition, results of operations and cash flows.
In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins
that we can earn on the volumes we are able to serve. Further, with retail competition, it is easier for residential customers
where we serve load to switch competitive electricity generation suppliers for their energy needs. The volatility and uncertainty
that results from such mobility may have material adverse effects on our financial condition, results of operations and cash
flows. For example, if fewer customers switch to another supplier than anticipated, the load we must serve will be greater than
anticipated, and if market prices of fuel have increased, our costs will increase more than expected due to the need to go to the
market to cover the incremental supply obligation. If more customers switch to another supplier than anticipated, the load we
must serve will be lower than anticipated and, if market prices of electricity have decreased, our operating results could suffer.
24

Our results of operations and financial condition could be materially and adversely affected by energy market participants
continuing to construct new generation facilities or expanding or enhancing existing generation facilities despite relatively
low power prices and such additional generation capacity results in a reduction in wholesale power prices.
Given the overall attractiveness of certain markets in which we operate and certain tax benefits associated with renewable
energy, among other matters, energy market participants have continued to construct new generation facilities or invest in
enhancements or expansions of existing generation facilities despite relatively low wholesale power prices. Assuming this
market dynamic continues, our results of operations and financial condition could be materially and adversely affected if such
additional generation capacity results in an over-supply of electricity that causes a reduction in wholesale power prices.
Additionally, new or existing market participants without, or with less, fossil fuel operations may gain additional market share,
or reduce our market share, due to evolving expectations and sentiments of key stakeholders, government, and regulatory
authorities regarding our operations and activities.
Economic downturns would likely have a material adverse effect on our businesses.
Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including
lower prices for power, generation capacity and natural gas, which can fluctuate substantially. Increased unemployment of
residential customers and decreased demand for products and services by commercial and industrial customers resulting from
an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible customer
balances, which would negatively impact our overall sales and cash flows. The convergence of current global conditions,
including sustained inflation, elevated interest rates, and the geopolitical climate, has and could lead to, or accelerate or
exacerbate the occurrence of, a significant economic downturn, as well as changes in consumer and counterparty behavior,
higher costs of capital, decreases in the value of our existing long-dated contracts, commodity price increases and volatility,
supply chain shortages, and other adverse impacts to our business. For example, the U.S. administration has taken action or may
take action in the future with respect to major changes to trade policies, such as the imposition of tariffs on imported products
and the withdrawal from or renegotiation of certain trade agreements. Any such material changes in trade policies, including the
imposition of tariffs, could lead to increased supply chain disruptions and increased supply chain costs, which could have a
material adverse impact on our business, financial condition and results of operations.
Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during
times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in
the future, which could have a material adverse effect on us. Vistra currently maintains non-investment grade credit ratings
that could negatively affect our ability to access capital on favorable terms or result in higher collateral requirements,
particularly if our credit ratings were to be downgraded in the future.
Our businesses are capital intensive. In general, we rely on access to financial markets and credit facilities as a significant
source of liquidity for our capital requirements, hedging transactions and other obligations not satisfied by cash-on-hand or
operating cash flows. The inability to raise capital or to access credit facilities, particularly on favorable terms, could adversely
impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs
and collateral requirements, any of which could have a material adverse effect on us.
Our access to capital and the cost and other terms of acquiring capital are dependent upon, and could be adversely
impacted by, various factors, including:
•
general economic and capital markets conditions, including changes in financial markets that reduce available
liquidity or the ability to obtain or renew credit facilities on favorable terms or at all;
•
conditions and economic weakness in the U.S. power markets;
•
regulatory developments;
•
changes in interest rates;
•
a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;
•
a downgrade of Vistra's or its applicable subsidiaries' credit ratings, or credit ratings of its issuances;
•
our level of indebtedness and compliance with covenants in our debt agreements;
•
our ability to meet our sustainability targets in our secured credit facilities;
•
a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit
facilities that affects the ability of such lender(s) to make loans to us;
•
credit, security, or collateral requirements, including those relating to volatility in commodity prices;
•
general credit availability from banks or other lenders for us and our industry peers;
•
investor and lender confidence in and sentiment of the industry, our business, and the wholesale electricity markets in
which we operate;
25

•
a material breakdown in or oversight in effectuating our risk management procedures;
•
the occurrence of changes in our businesses;
•
disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities and battery
ESS; and
•
changes in or the operation of provisions of tax and regulatory laws.
There are also increasing financial risks for companies that own and operate fossil fuel generation as institutional lenders
or other sources of capital have become more attentive to sustainable financing practices and some of them may seek
commitments on emission reduction targets or expected use or proceeds when providing funding to, or decline to provide
funding for companies who produce or utilize fossil fuel energy or that have higher levels of GHG emissions. Our Vistra
Operations Credit Agreement contains Sustainability Adjustments. These adjustments use baseline values from KPI Metrics
and provide for decreases in the applicable credit spread adjustments and commitment fee rates if our reported metrics are a
certain percentage below the baseline values, adjusted on a year-to-year basis. Conversely, if our reported metrics are a certain
percentage above the baseline values, adjusted on a year-to-year basis, the applicable credit spread adjustments and fee rates are
increased. Building in these adjustments to our credit agreement helps to show lenders we are committed to lowering our GHG
emissions, but failing to meet the targets on a regular basis could be viewed negatively by such lenders. Additionally, the
lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in
nature, by environmental activists and others concerned about climate change not to provide funding for companies in the
broader energy sector. Limitations on our access to, or increases in our cost of, capital could have a material adverse effect on
us.
In addition, Vistra currently maintains non-investment grade credit ratings. As a result, we may not be able to access
capital on terms (financial or otherwise) as favorable as companies that maintain investment-grade credit ratings or we may be
unable to access capital at all at times when the credit markets tighten. In addition, due to our non-investment grade credit
ratings, counterparties request collateral support (including cash or letters of credit) in order to enter into certain transactions
with us.
A downgrade in long-term debt ratings generally causes borrowing costs to increase and the potential pool of investors to
shrink and could trigger liquidity demands pursuant to contractual arrangements. Future transactions by Vistra or any of its
subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit ratings.
Our indebtedness could adversely affect our ability in the future to raise additional capital to fund our operations. It could
also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy, or our industry,
as well as impact our cash available for distribution.
As of December 31, 2024, we had approximately $18.4 billion of total indebtedness and approximately $17.2 billion of
indebtedness net of cash. Our debt could have negative consequences for our financial condition including:
•
increasing our vulnerability to general economic and industry conditions;
•
requiring a significant portion of our cash flows from operations to be dedicated to the payment of principal and
interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our common stock or to
fund our operations, capital expenditures and future business opportunities;
•
limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
•
limiting our ability to fund operations or future acquisitions;
•
limiting our ability to repurchase shares under the share repurchase program;
•
restricting our ability to make distributions or pay dividends with respect to our common and preferred stock and the
ability of our subsidiaries to make distributions to us, in light of restricted payment and other financial covenants in
our credit facilities and other financing agreements;
•
inhibiting the growth of our stock price;
•
exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under the
Vistra Operations Credit Facilities, are at variable rates of interest, only a portion of which are hedged;
•
limiting our ability to obtain additional financing for working capital including collateral postings, capital
expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
•
limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to
our competitors who may have less debt.
26

We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to
refinance or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof. Our
failure to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default
under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of
operations and cash flows.
The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures,
contain restrictions and limitations that could affect our ability to operate our business, or liquidity, and results of
operations, and any failure to comply with these restrictions could have a material adverse effect on us.
The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures,
contain restrictions that could adversely affect us by limiting our ability to operate our businesses and plan for, or react to,
market conditions or to meet our capital needs and could result in an event of default under the Vistra Operations Credit
Facilities, indentures and/or our other debt facilities. The Vistra Operations Credit Facilities, indentures and our other debt
facilities contain events of default customary for financings of such type. If we fail to comply with the covenants in the Vistra
Operations Credit Facilities, indentures and/or our other debt facilities and are unable to obtain a waiver or amendment, or a
default exists and is continuing, the lenders under such agreements or notes, as the case may be, could give notice and declare
outstanding borrowings thereunder immediately due and payable. The breach of any covenants or obligations in certain
agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, not otherwise
waived or amended, could result in a default under the applicable debt obligations and could trigger acceleration of those
obligations, which in turn could trigger cross defaults under other agreements governing our debt, and any such acceleration of
outstanding borrowings could have a material adverse effect on us.
Certain obligations are required to be secured by letters of credit, surety bonds, first liens, or cash, which increase our costs.
If we are unable to provide such security, it may restrict our ability to conduct our business, which could have a material
adverse effect on us.
We undertake certain hedging and commodity activities and enter certain financing arrangements with various
counterparties that require cash collateral or the posting of letters of credit which are at risk of being drawn down in the event
we default on our obligations. We currently use margin deposits, prepayments, surety bonds, letters of credit and first liens as
credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase
based on the extent of our involvement in standard contracts and movements in commodity prices, the use of first lien
collateral, and also based on our credit ratings and the general perception of creditworthiness in the markets in which we
operate. In the case of commodity arrangements, the amount of such credit support that must be provided is typically based on
the difference between the price of the commodity in a given contract and the market price of the commodity. Significant
movements in market prices can result in our being required to provide cash collateral and letters of credit in very large
amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain
these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without enough working
capital or other sources of available liquidity to post as collateral, we may not be able to manage price volatility effectively or to
implement our strategy. A material increase in the amount of letters of credit or cash collateral required to be provided to our
counterparties may have a material adverse effect on us.
27

We may not be able to complete future acquisitions on favorable terms or at all, successfully integrate future acquisitions
into our business, or effectively identify and invest in value-creating businesses, assets or projects, which could result in
unanticipated expenses and losses or otherwise hinder or delay our growth strategy.
As part of our growth strategy, including our desire to grow our retail platform, we may pursue acquisitions of assets or
operating entities. This strategy depends on the Company's ability to successfully identify and evaluate acquisition opportunities
and consummate acquisitions on favorable terms. Our ability to continue to implement this component of our growth strategy
will be limited by our ability to identify appropriate acquisition or joint venture candidates and our financial resources,
including available cash and access to capital. In addition, the Company will compete with other companies for these limited
acquisition opportunities, which may increase the Company's cost of making acquisitions or limit the Company’s ability to
make acquisitions at all. Any expense incurred in completing acquisitions or entering into joint ventures, the time it takes to
integrate an acquisition or our failure to integrate acquired businesses successfully could result in unanticipated expenses and
losses. Furthermore, we may not be able to fully realize the anticipated benefits from any future acquisitions or joint ventures
we may pursue. In addition, the process of integrating acquired operations into our existing operations may involve unknown
risks, result in unforeseen operating difficulties and expenses, and may require significant financial resources that would
otherwise be available for the execution of our business strategy. If the Company is unable to identify and consummate future
acquisitions, it may impede the Company's ability to execute its growth strategy.
Our ability to achieve the expected growth of our Vistra Zero portfolio, consisting of our solar generation, battery ESS, and
other renewables development projects, is subject to substantial capital requirements and other significant uncertainties.
We have a substantial capital allocation plan intended for investments in renewable assets, including solar development
projects and battery ESS. As part of our business strategy, we plan to continually assess potential strategic acquisitions or
investments in renewable assets, emerging technologies and related projects. Notably, the Company's ability to successfully
develop our current renewables projects, or in the future acquire additional renewable assets, may be impacted by the demand
for and viability of renewable assets generally, which may vary depending on availability of projects and financing, as well as
public policy, financial and tax mechanisms implemented at the state and federal levels to support the development of
renewable assets. Various factors could result in increased costs or result in delays or cancellation of our current or future
renewable projects, or the loss of, or declines in the value of, our investments in projects including, but not limited to, risks
relating to siting, financing, engineering and construction, permitting, interconnection requests, federal and state regulatory
approvals, new legislation or regulatory changes impacting the industry, commissioning delays, import tariffs, changes to
federal income tax laws, economic events or factors, environmental and community concerns, availability of or requirements
for additional funding, enhanced competition, or the potential for termination of the power sales contract as a result of a failure
to meet certain milestones. Further, the recent proliferation of renewable projects has resulted in a large volume of
interconnection requests submitted to grid operators, including the markets in which we operate, resulting in significant delays
to the approval process and estimated completion dates for our projects and others. FERC and regional ISOs are working to
address these backlogs, including with regulatory rule changes, changing the interconnection process, the impacts of which are
currently unknown because the changes have only been partially implemented. Additionally, the increased demand for
construction of renewables projects, such as battery ESS and solar projects, and other labor market and supply chain constraints
have resulted, and may continue to result, in limited availability of qualified specialists, contractors, and necessary services or
materials, leading to delays in and higher costs for the development and construction of our current and future planned projects.
Should any of these factors occur, our financial position, results of operations, and cash flows could be adversely affected, or
our future growth opportunities may not be realized as anticipated.
While certain of our subsidiaries are in various stages of developing and constructing solar generation facilities and
battery ESS and certain of these projects have signed long-term contracts or made similar arrangements for the sale of
electricity, in other cases, our subsidiaries may enter into obligations in the development process even though the subsidiaries
have not yet secured power purchase arrangements or other important elements for a successful project. If the project does not
proceed as planned, our subsidiaries may remain obligated for certain liabilities even though the project will not be completed.
Development is inherently uncertain and we may forgo certain development opportunities and we may undertake significant
development costs before determining that we will not proceed with a particular project. We believe that capitalized costs for
projects under development are recoverable; however, there can be no assurance that any individual project will be completed
and reach commercial operation. If these development efforts are not successful, we may abandon a project under development
and write off the costs incurred in connection with such project and could incur additional losses associated with any related
contingent liabilities.
28

Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition.
In evaluating our business and the strategic fit of our various assets, we may determine to sell one or more of such assets.
Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an
acceptable price and on acceptable terms and in a timely manner. In addition, a prospective buyer may have difficulty obtaining
financing. Divestitures could involve additional risks, including:
•
difficulties in the separation of operations and personnel;
•
the need to provide significant ongoing post-closing transition support to a buyer;
•
management's attention may be temporarily diverted;
•
the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;
•
the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;
•
the disruption of our business; and
•
potential loss of key employees.
We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset,
which could adversely affect our results of operations and financial condition.
If our goodwill, intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to
earnings.
Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to our retail trade names are
not amortized and are subject to impairment testing annually, or when events or changes in the business environment indicate
that the carrying value of the reporting unit may exceed its fair value. Additionally, we evaluate long-lived assets (including
intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that their carrying
amount may not be recoverable. Any reduction in or impairment of the value of goodwill, intangible assets, or other long-lived
assets will result in a charge against earnings, which could materially adversely affect our reported results of operations and
financial position in future periods.
If an impairment of goodwill, intangible assets with indefinite useful lives, or long-lived assets is realized, it may result in
a significant charge to earnings in the respective quarterly or annual financial results prepared in accordance with GAAP.
Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in
an ownership change as defined in Internal Revenue Code (IRC) §382 could further limit our ability to use certain tax
attributes and our federal net operating losses to offset our future taxable income.
If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs that could be
used in any one year following such ownership change could be substantially limited. In general, an "ownership change" would
occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of
which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock. Given IRC §382's broad
definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is
outside our control. Vistra acquired NOLs from its merger with Dynegy; however, Vistra's use of such attributes is limited
under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy. If there is an "ownership
change" with respect to Vistra (including by the normal trading activity of greater than 5% stockholders), the utilization of all
NOLs existing at that time would be subject to additional annual limitations based upon a formula provided under IRC §382
that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership change. In
addition, any ownership change with respect to Vistra could result in additional limitations on our ability to use certain tax
attributes, including depreciation, existing at the time of any such ownership change and have an impact on our tax liabilities.
29

Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or
increased taxes or fees, could have a material adverse effect on our financial condition, results of operations and cash flows.
We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time,
legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There
can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures. The
Tax Cuts and Jobs Act of 2017 (TCJA), enacted December 22, 2017, and the Inflation Reduction Act (IRA), enacted August
16, 2022, both introduced significant changes to current U.S. federal tax law. For example, the IRA includes the enactment of
several new proposals, including, but not limited to (i) a corporate alternative minimum tax based on book income and (ii)
additional requirements to qualify for enhanced renewable energy tax credits. These changes are complex and continue to be the
subject of additional guidance issued by the U.S. Treasury and the Internal Revenue Service. In addition, the reaction to the
federal tax changes by the individual states continues to evolve. Our interpretations and assumptions around U.S. tax reform
may evolve in future periods as further administrative guidance and regulations are issued, which may materially affect our
effective tax rate or tax payments.
U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There
can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there
could be a material impact on our results of operations and financial condition.
U.S. federal income tax reform and changes in other tax laws could adversely affect us. Additionally, states in which we
operate or own assets may impose new or increased taxes or fees on various aspects of our operations. The passage of any
legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or
increased taxes or fees could have a material adverse effect on our financial condition, results of operations and cash flows.
If electricity demand does not grow at the rate expected, or if we are unable to execute on large load offtake opportunities,
our financial performance, growth opportunities, and stock price could be adversely impacted.
Multiple demand drivers such as emergence of large load data centers, including in response to transformations in
technologies like artificial intelligence (AI) and electrification of oil field operations (specifically in the Permian Basin of west
Texas), have accelerated, and are expected to continue to accelerate, load growth in the geographic regions we serve. We
continue to pursue opportunities for the potential sale of power from our existing or new nuclear and gas facilities pursuant to
long-term agreements to supply large load facilities. Such potential transactions are subject to certain risks and uncertainties,
including various currently contemplated or future potential regulatory actions, reviews, and/or approvals and legislative
actions, which could impact the timing of, and our ability to consummate, a potential transaction. In addition, if demand does
not continue to increase at a rate in line with market expectations due to various factors, such as changes in technology, more
energy efficient AI solutions or slow adoption of AI products and services, economic downturns, or adverse government
actions, or if we are unable to execute on such large load offtake opportunities, our opportunities for growth and stock price
may be adversely impacted.
Regulatory and Legislative Risks
Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely impacted, and
may in the future adversely impact, our businesses, results of operations, liquidity, financial condition, and cash flows.
Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory
initiatives regarding the restructuring of the energy industry, including competition in power generation and sale of electricity,
natural gas, emissions and renewable energy certificates, and other commodities. Although we attempt to comply with changing
legislative and regulatory requirements, there is a risk that we will fail to adapt to any such changes successfully or on a timely
basis. Compliance with, or changes to, the requirements under these legal and regulatory regimes, including those proposed or
implemented under the current presidential administration or during any future change of administration, or any repeal of
existing beneficial laws or regulations, may adversely impact our businesses, results of operations, liquidity, financial condition,
and cash flows.
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Our businesses are subject to numerous state and federal laws (including, but not limited to, Texas Public Utility
Regulatory Act, the Federal Power Act, the Natural Gas Policy Act, the Atomic Energy Act, the Public Utility Regulatory
Policies Act of 1978, the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act
(RCRA), the Energy Policy Act of 2005, the Dodd-Frank Wall Street Reform and the Consumer Protection Act and the
Telephone Consumer Protection Act), changing governmental policy and regulatory actions (including those of the FERC, the
NERC, the RCT, the MSHA, the EPA, the NRC, the DOJ, the FTC, the CFTC, state public utility commissions and state
environmental regulatory agencies), and the rules, guidelines and protocols of ERCOT, CAISO, ISO-NE, MISO, NYISO and
PJM with respect to various matters, including, but not limited to, market structure and design, operation of nuclear generation
facilities, construction and operation of other generation facilities, development, operation and reclamation of lignite mines,
recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail
competition, administrative pricing mechanisms (and adjustments thereto), rates for wholesale sales of electricity, mandatory
reliability standards and environmental matters. We, along with other market participants, are subject to electricity pricing
constraints and market behavior and other competition-related rules and regulations. Additionally, Ambit’s direct selling
business (i) could be found by regulators not to be in compliance with applicable law or regulations, which may lead to our
inability to obtain or maintain a license, permit, or similar certification and (ii) may be required to alter its compensation
practices in order to comply with applicable federal or state law or regulations. Changes in, revisions to, or reinterpretations of,
existing laws and regulations may have a material adverse effect on our businesses, results of operations, liquidity, financial
condition and cash flows.
Extreme weather events have resulted, and in the future may result, in efforts by both federal and state government and
regulatory agencies to investigate and determine the causes of such events. For example, as a result of Winter Storm Uri, we
received a civil investigative demand from the Attorney General of Texas as well as a request for information from ERCOT,
NERC, and other regulatory bodies related to this event. Winter Storm Elliott, in December 2022, also led to regulatory
requests for information and notices of investigation by NERC, FERC, regional reliability entities, and independent market
monitors for regions across the country. Such investigations have resulted, and in the future may result, in changes in laws or
regulations that impact our industry and businesses including, but not limited to, additional requirements for winterization of
various facets of the electricity supply chain including generation, transmission, and fuel supply; improvements in coordination
among the various participants in the electricity supply chain during any future event; restrictions or limitations on the types of
plans permitted to be offered to customers; potential revisions to the method of calculation of market compensation and
incentives relating to the continued operation of assets that only run periodically, including during extreme weather events or
other times of scarcity; and other potential legislative and regulatory corrective actions that may be taken. Previously
announced or future legal proceedings, regulatory actions, or other administrative proceedings involving market participants
may lead to adverse determinations or other findings of violations of laws, rules, or regulations, any of which may impact the
ability of market participants to satisfy, in whole or in part, their respective obligations. For example, the Texas Legislature, the
PUCT, ERCOT, FERC, and NERC have implemented new requirements and continue to consider future market design and
other rule changes in response to Winter Storm Uri and other extreme weather events.
Finally, the regulatory environment has undergone significant changes in the last several years due to state and federal
policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new
renewable generation. For example, changes to, or development of, legislation that requires the use of clean renewable and
alternate fuel sources or mandate the implementation of energy conservation programs that require the implementation of new
technologies, could increase our capital expenditures and/or impact our financial condition. Changes enacted by the Texas
Legislature through Senate Bill 2627, the Powering Texas Forward Act, to administer Texas Energy Fund (TEF) programs,
which include grants and loans to finance the construction, maintenance, modernization, and operation of electric facilities in
Texas, may negatively impact our financial condition if it materially changes market fundamentals. Additionally, in some retail
energy markets, state legislators, government agencies and other interested parties have made proposals to change the use of
market-based pricing, re-regulate areas of these markets that have previously been competitive, or permit electricity delivery
companies to construct or acquire generation facilities. Other proposals to re-regulate the retail energy industry may be made,
and legislative or other actions affecting electricity and natural gas deregulation or restructuring process may be delayed,
discontinued or reversed in states in which we currently operate or may in the future operate. If such changes were to be enacted
by a regulatory body, we may lose customers, incur higher costs and/or find it more difficult to acquire new customers. These
changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effect that the
changing regulatory environment will have on our business.
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We are required to obtain, and to comply with, government permits and approvals.
We are required to obtain, and to comply with, numerous permits and licenses from federal, state and local governmental
agencies. The process of obtaining and renewing necessary permits and licenses can be lengthy and complex and can sometimes
result in the establishment of conditions that make the project or activity for which the permit or license was sought
unprofitable or otherwise unattractive. In addition, such permits or licenses may be subject to denial, revocation or modification
under various circumstances. Failure to obtain or comply with the conditions of permits or licenses, or failure to comply with
applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the
curtailment of our delivery of electricity to our customers and may subject us to penalties and other sanctions. Although various
regulators routinely renew existing permits and licenses, renewal of our existing permits or licenses could be denied or
jeopardized by various factors, including (a) failure to provide adequate financial assurance for closure, (b) failure to comply
with environmental, health and safety laws and regulations or permit conditions, (c) local community, political or other
opposition and (d) executive, legislative or regulatory action.
Our inability to procure and comply with the permits and licenses required for our operations, or the cost to us of such
procurement or compliance, could have a material adverse effect on us. In addition, new environmental legislation or
regulations, if enacted, or changed interpretations of existing laws, may cause activities at our facilities to need to be changed to
avoid violating applicable laws and regulations or elicit claims that historical activities at our facilities violated applicable laws
and regulations. In addition to the possible imposition of fines in the case of any such violations, we may be required to
undertake significant capital investments and obtain additional operating permits or licenses, which could have a material
adverse effect on us.
Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.
We are subject to extensive environmental regulation by governmental authorities, including federal and state
environmental agencies and/or attorneys general. We may incur significant additional costs beyond those currently
contemplated to comply with these regulatory requirements. If we fail to comply with these regulatory requirements, we could
be subject to administrative, civil or criminal liabilities and fines. Existing environmental regulations could be revised or
reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in
environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air
emissions and CCR, all of which could result in significant additional costs beyond those currently contemplated to comply
with existing requirements. Any of the foregoing could have a material adverse effect on us.
The Biden Administration recently finalized or proposed several regulatory actions establishing new requirements for
control of certain emissions from sources, including electricity generation facilities. In the future, the EPA may also propose
and finalize additional regulatory actions that may adversely affect our existing generation facilities or our ability to cost-
effectively develop new generation facilities. There is no assurance that the currently installed emissions control equipment at
our lignite, coal and/or natural gas-fueled generation facilities will satisfy the requirements under any future EPA or state
environmental regulations. Some of the recent regulatory actions, such as the EPA's Good Neighbor Plan for the 2015 Ozone
NAAQS, the final rule to regulated GHG emissions that would replace the ACE rule, and actions under the Regional Haze
program, could require us to install significant additional control equipment, resulting in potentially material costs of
compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production
curtailments or plant retirements. These costs or operation impacts could have a material adverse effect on us. In January 2025,
President Trump issued a series of executive orders, including an order titled Unleashing American Energy (the "Order") that
ordered that all federal agencies are to review all existing regulations, orders and other actions for consistency with the policy
goals in that Order, and develop an action plan within 30 days to resolve any policy inconsistencies. In addition, the Order
stated that the U.S. Attorney General may request stays of litigation involving any identified rules or actions from the review.
We expect the Trump Administration to review the recent actions of the Biden Administration, but the outcome of those actions
is uncertain.
We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining
any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an
approval is retroactively disallowed or adversely modified, the operation of our generation facilities could be stopped,
disrupted, curtailed or modified or become subject to additional costs. Any such stoppage, disruption, curtailment, modification
or additional costs could have a material adverse effect on us.
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In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that
we have acquired, leased, developed or sold, regardless of when the liabilities arose and whether they are now known or
unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification
against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim
against us or fail to meet its indemnification obligations to us, which could have a material adverse effect on us.
We could be materially and adversely affected if new federal or state legislation or regulations are adopted to address global
climate change that could require efforts that exceed or are more expensive than our currently planned initiatives or if we
are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.
There is continuing emphasis nationally and internationally on global climate change and how GHG emissions, such as
CO2, contribute to global climate change. Over the last several years, the U.S. Congress has considered and debated several
proposals intended to address climate change using different approaches, including a cap on carbon emissions with emitters
allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the
development of low-carbon technology and federal renewable portfolio standards. In July 2019, the EPA finalized the ACE rule
that developed emissions guidelines that states must use when developing plans to regulate GHG emissions from existing coal-
fueled electric generation units. In January 2021, the ACE rule was vacated by the D.C. Circuit Court and remanded to the EPA
for further consideration in accordance with the court's ruling. The D.C. Circuit Court's decision was appealed to the U.S.
Supreme Court. In June 2022, the U.S. Supreme Court issued its decision in West Virginia v. EPA, in which it held that the EPA
does not have the authority to apply generation shifting in the regulation of GHG emissions. The judgment reversed the D.C.
Circuit Court's decision and remanded the case for further proceedings consistent with the U.S. Supreme Court's opinion. In
May 2024, the EPA issued a more stringent and more encompassing rule to replace the ACE rule. The GHG rule issued in May
2024 is currently being challenged in the D.C. Circuit after the U.S. Supreme Court declined to issue a stay of that rule. We
expect the Trump Administration to review the May 2024 GHG rule. Additionally, pursuant to the Order, the Administrator of
the EPA, in collaboration with the heads of any other relevant agencies, will submit joint recommendations to the Director of
the Office of Management and Budget on the legality and continuing applicability of the December 2009 Endangerment
Finding. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG
emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us)
that produce GHG emissions. We could be materially and adversely affected if federal and/or state legislation or regulations
that address global climate change require efforts that exceed or are more expensive than our currently planned initiatives or if
we are subject to lawsuits for alleged damage to persons or property resulting from GHG emissions.
Additionally, in January 2021, President Biden issued written notification to the United Nations of the U.S.'s intention to
rejoin the Paris Agreement, effective in February 2021. However, in January 2025, President Trump signed an Executive Order
announcing the withdrawal from the Paris Agreement.
Luminant's mining operations are subject to RCT oversight.
We currently own and operate, or are in the process of reclaiming, various surface lignite coal mines in Texas to provide
fuel for our electricity generation facilities. We also own or lease, and are in the process of reclaiming, multiple waste-to-energy
surface facilities in Pennsylvania. The RCT, which exercises broad authority to regulate reclamation activity, reviews on an
ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all the requirements of its
mining permits in Texas. Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface
Mining, which also regulates mining activity nationwide, or any changes in the interpretation of existing rules and regulations,
could result in higher compliance costs or otherwise adversely affect our financial condition or cause a revocation of a mining
permit. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the
applicable mine to serve its generation facilities.
Luminant's lignite mining reclamation activity will require significant resources as existing and retired mining operations
are reclaimed over the next several years.
In conjunction with Luminant's announcements in 2017 to retire several power generation assets and related mining
operations, along with the reclamation obligations at the closed Martin Lake mines and continuous reclamation activity at its
continuing mining operations for its mines related to the Oak Grove generation asset, Luminant is expected to spend a
significant amount of money, internal resources and time to complete the required reclamation activities. For the next five
years, Vistra is projected to spend approximately $238 million (on a nominal basis) to achieve its mining reclamation
objectives.
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Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant
liabilities and reputational damage that could have a material adverse effect on us.
We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment,
commercial, and environmental issues, and other claims for injuries and damages. We evaluate litigation claims and legal
proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, potential losses. Based on these
evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant
litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to
management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from
current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse
effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a
significant business risk.
We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings,
and we are exposed to the risk of additional regulatory investigations or administrative proceedings. As we adopt new
technologies, like artificial intelligence (AI), there is a risk that the content, analyses, recommendations, or judgments that AI
applications assist in producing are alleged to be deficient, inaccurate, biased, or infringe on other's rights or property interests.
Any such regulatory investigation or administrative proceeding could result in us incurring penalties and other costs which may
have a material adverse effect on us.
Our retail businesses, which each have REP certifications that are subject to review of the public utility commissions in the
states in which we operate, are subject to changing state rules and regulations that could have a material impact on the
profitability of our business.
The competitiveness of our U.S. retail businesses partially depends on state regulatory policies that establish the structure,
rules, terms and conditions on which services are offered to retail customers. Specifically, the public utility commissions and/or
the attorney generals of the various jurisdictions in which the Retail segment operates may at any time initiate an investigation
into whether our retail operations comply with certain commission rules or state laws and whether we have met the
requirements for REP certification, including financial requirements. These state policies and investigations, which can include
controls on the retail rates our retail businesses can charge, the imposition of additional costs on sales, restrictions on our ability
to obtain new customers through various marketing channels and disclosure requirements, investigations into whether our retail
operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification,
including financial requirements, can affect the competitiveness of our retail businesses. Any removal or revocation of a REP
certification would mean that we would no longer be allowed to provide electricity service to retail customers in the applicable
jurisdiction, and such decertification could have a material adverse effect on us. Additionally, state or federal imposition of net
metering or renewable portfolio standard programs can make it more or less expensive for retail customers to supplement or
replace their reliance on grid power. Our retail businesses may have limited ability to influence development of these state
rules, regulations and policies, and our business model may be more or less effective, depending on changes to the regulatory
environment.
Operational Risks
Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance
of our retail businesses.
Although we are the primary provider of our retail businesses' wholesale electricity supply requirements, our retail
businesses purchase a portion of their supply requirements from third parties. As a result, the financial performance of our retail
business depends on their ability to obtain adequate supplies of electric generation from third parties at prices below the prices
they charge their customers. Consequently, our earnings and cash flows could be adversely affected in any period in which the
retail businesses' wholesale electricity supply costs rise at a greater rate than the rates they charge to customers. The price of
wholesale electricity supply purchases associated with the retail businesses' energy commitments can be different than that
reflected in the rates charged to customers due to, among other factors:
•
varying supply procurement contracts used and the timing of entering into related contracts;
•
subsequent changes in the overall price of natural gas;
•
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
•
transmission constraints and the Company's ability to move power to our customers;
•
out-of-market payments, uplifts, or other non-pass through charges, and
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•
changes in Market Heat Rate.
The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers'
actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors,
transmission and distribution outages, demand-side management programs, competition and economic conditions, or extreme
weather events, such as Winter Storm Uri in February 2021.
Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing
customers and the inability to attract new customers.
We operate in a very competitive retail market where our retail operation faces significant competition for customers. We
believe our brands are viewed favorably in these markets, but despite our commitment to providing superior customer service
and innovative products, customer sentiment toward our brands, including by comparison to our competitors' brands, depends
on certain factors beyond our control. For example, competitor REPs may offer different products, lower electricity prices and
other incentives, which, despite our long-standing relationship with many customers, may attract customers away from us. If we
are unable to successfully compete with competitors in the retail market it is possible our retail customer counts could decline,
which could have a material adverse effect on us.
As we try to grow our retail business and operate our business strategy, we compete with various other REPs that may
have certain advantages over us. For example, in new markets, our principal competitor for new customers may be the
incumbent REP, which has the advantage of long-standing relationships with its customers, including well-known brand
recognition. In addition to competition from the incumbent REP, we may face competition from a number of other energy
service providers, other energy industry participants, or nationally branded providers of consumer products and services who
may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger than we
are or have greater resources or access to capital than we have. Competitors may also incorporate emerging technology like
generative AI into their businesses, services, and products more quickly or more successfully than we do. In retail markets with
substantial competition, high customer acquisition costs may outweigh the potential margin and it may not be profitable for us
to compete in these markets.
Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide
electricity to, and to obtain information about, our customers. Any infrastructure failure could negatively impact customer
satisfaction and could have a material adverse effect on us.
The substantial majority of our retail operations depend on transmission and distribution facilities owned and operated by
unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capacity is inadequate, our ability to
sell and deliver electricity may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is
available in the capacity-constrained area or, with respect to capacity performance in PJM and performance incentives in ISO-
NE, we may be subject to significant penalties. For example, during some periods, transmission access is constrained in some
areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to
these customers may exceed the cost to provide service to other customers, resulting in lower operating margins. In addition,
any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer
satisfaction with our service. Any of the foregoing could have a material adverse effect on us.
Cybersecurity attacks or technology systems failures could disrupt business operations and expose us to significant
liabilities, reputational damage, loss of customers, and regulatory action.
Our businesses depend on the secure and reliable storage, processing and communication of electronic data and
sophisticated computer hardware and software systems. Our information technology systems and infrastructure, and those of
our vendors and suppliers, face constant threats that have in the past and could in the future compromise data confidentiality,
integrity, or availability. While we have controls in place designed to protect our information technology (IT) infrastructure,
such breaches and threats are becoming increasingly sophisticated and complex, requiring the continuing evolution of our
program. A breach or similar IT incident could interrupt normal business operations and affect our ability to use our generation
assets, customer information, or communication systems, which could have a material adverse effect on us.
Potential disruptions from cyber/data and physical security breaches to "critical cyber assets" that interrupt the delivery of
power to the Bulk Electric System could incur penalties of up to $1 million per violation for failure to comply with mandatory
electric reliability standards by FERC under the Energy Policy Act of 2005.
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Further, our retail business requires us to regularly access, collect, store, and transmit customer data, including sensitive
customer data. New data privacy and data protection laws and regulations, increased enforcement, and other government
actions could impact our businesses, increase compliance costs, and failure to comply with these laws and regulations could
adversely affect our business and financial results. Our retail business may need to provide access to customer data, including
sensitive customer data, to third parties and service providers to provide services, such as call center operations. In certain
circumstances, Vistra could incur liability for a third-party or service provider's misuse or loss of the data.
Although we take precautions to protect our infrastructure, we have been, and will likely continue to be, subject to
attempts at phishing and other cybersecurity intrusions. International conflict increases the risk of state-sponsored cyber threats
and escalated use of cybercriminal and cyber-espionage activities. In particular, the current geopolitical climate has further
escalated cybersecurity risk, with various government agencies, including the Federal Bureau of Investigation (FBI) and the
U.S. Cybersecurity & Infrastructure Security Agency, issuing warnings of increased cyber threats, particularly for U.S. critical
infrastructure. As of the date of this report, the Company has not identified a cyber/data event causing any material operational,
reputational or financial impact. However, we recognize the growing threat within the general marketplace and our industry,
especially as generative AI becomes more widely used by threat actors. There is no assurance that we will be able to prevent or
mitigate any such impacts in the future. In the event of a material cyber breach, critical operational capabilities to support our
generation, commercial, or retail operations could be disrupted or lost. Additionally, customer, confidential, or proprietary data
could be compromised, misused, or inappropriately disclosed. If critical operational capabilities or data were impacted, it could
adversely affect our reputation, diminish customer confidence, expose us to legal or regulatory claims, impair our business
strategy, or impact our results of operation or financial condition, which could have a material adverse effect on us. Our efforts
to deter, identify, and mitigate future breaches may require additional, significant capital and operating costs and may not be
successful.
We may suffer material losses, costs and liabilities due to operation risks, regulatory risks, and the risk of nuclear accidents
arising from the ownership and operation of the nuclear generation facilities.
We own and operate nuclear generation facilities in Texas, Ohio, and Pennsylvania. The ownership and operation of
nuclear generation facilities involves certain risks. These risks include:
•
unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity, insider threat,
third-party compromise or other problems;
•
inadequacy or lapses in maintenance protocols;
•
the impairment of reactor operation and safety systems due to human error or force majeure;
•
the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive
materials;
•
the costs of procuring nuclear fuel, including impacts from trade restrictions such as tariffs, embargoes, and quotas
(see Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations – Significant
Activities and Events, and Items Influencing Future Performance – Macroeconomic Conditions);
•
the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;
•
terrorist or cybersecurity attacks by nation-states or other threat actors and the cost to protect and recover against any
such attack;
•
the impact of a natural disaster;
•
financial risk associated with retrospective insurance premium that could become due under secondary coverage
required by the Price Anderson Act;
•
limitations on the amounts and types of insurance coverage commercially available; and
•
uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear
facilities at the end of their useful lives.
Our financial performance could be materially and negatively affected by matters arising from our ownership and
operation of nuclear facilities, including any prolonged unavailability of any of our nuclear generation facilities. The following
are among the more significant related risks:
•
Operational Risk. Operations at any generation facility could degrade to the point where the facility would have to be
shut down. If such degradations were to occur at a nuclear generation facility, the process of identifying and correcting
the causes of the operational downgrade to return the facility to operation could require significant time and expense,
resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments.
Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-
down or reduced availability at our nuclear generation facilities.
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•
Regulatory Risk. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply
with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless
extended, as to which no assurance can be given, the NRC operating license for the unit at the Perry Facility will
expire in 2026, and is pending a license renewal application subject to review by the NRC. Changes in regulations by
the NRC could require a substantial increase in capital expenditures or result in increased operating or
decommissioning costs.
•
Spent Nuclear Fuel Storage. Our nuclear operations produce various types of nuclear waste materials, including spent
nuclear fuel. The availability of a national repository for the storage of spent nuclear fuel and the timing of that facility
opening will significantly affect the costs associated with storage of spent nuclear fuel and the ultimate amounts
received from the DOE to reimburse us for these costs. Any regulatory action relating to the timing and availability of
a repository for spent nuclear fuel could adversely affect our ability to decommission fully our nuclear units. We
cannot predict whether a fee may be established or to what extent in the future for spent nuclear fuel disposal.
•
Decommissioning Obligation and Funding. NRC regulations require that licensees of nuclear generating facilities
demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the
facility to decommission the facility.
Actual costs to decommission our nuclear facilities may substantially exceed our estimates as a result of changes in the
approach and timing of decommissioning activities, changes in decommissioning costs, changes in federal or state
regulatory requirements, other changes in our estimates or ability to effectively execute on our planned
decommissioning activities.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant
judgment, and actual results could differ significantly from current estimates. In addition, financial market
performance directly affects the asset values in the NDT trust funds. If the investments held by our PJM NDT funds
are not sufficient to fund the decommissioning of our nuclear units, we could be required to take steps, such as
providing financial guarantees through letters of credit or parent company guarantees or making additional
contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current
and future NRC minimum funding requirements are met.
•
Nuclear Accident Risk. Although the safety record of our nuclear generation facilities generally has been very good,
accidents and other unforeseen problems have occurred at nuclear stations both in the U.S. and elsewhere. The
consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property
damage. Any accident, or perceived accident, could result in significant liabilities that may exceed our resources,
including insurance coverages, and could damage our reputation. Such liabilities to third parties are currently covered
by a primary layer of financial protection required by the Price Anderson Act in the form of insurance carried by the
owners of each nuclear facility and by a secondary layer of insurance coverage into which each nuclear licensee in the
country is required to contribute in the event of an accident at any facility which exceeds the primary level of coverage
for that facility. Our potential exposure for the secondary layer of coverage is currently capped at $165.9 million per
reactor but is subject to adjustment for inflation, and the total retrospective premium per reactor per incident is capped
at $24.7 million in any one year. Any such resulting liability from a nuclear accident could exceed our resources,
including insurance coverage, and could ultimately result in the suspension or termination of power generation from
the impacted facility. Such accidents could also result in property damage to our nuclear plant and equipment, which
could exceed coverage available under insurance provided by Nuclear Electric Insurance Limited. If a serious nuclear
incident were to occur, our business, reputation, financial condition and results of operations could be materially
adversely affected.
37

The operation and maintenance of power generation facilities and related mining operations are capital intensive and
involve significant risks that could adversely affect our results of operations, liquidity and financial condition.
The operation and maintenance of power generation facilities and related mining operations involve many risks,
including, as applicable, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of
sufficient capital to maintain the facilities, the dependence on a specific fuel source, the ability to timely obtain parts for
equipment repairs, the inability to transport our product to our customers in an efficient manner due to the lack of transmission
capacity or the impact of unusual or adverse weather conditions or other natural events, or terrorist attacks, as well as the risk of
performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in substantial
lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. Older
generation equipment, even if maintained or refurbished in accordance with good engineering practices, may require significant
capital expenditures to operate at peak efficiency or reliability. The risk of increased maintenance and capital expenditures
arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation
market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of
all our generation facilities, (b) any unexpected failure to generate power, including failure caused by equipment breakdown or
unplanned outage (whether by order of applicable governmental regulatory authorities, the impact of weather events or natural
disasters or otherwise), (c) damage to facilities due to storms, natural disasters, wars, terrorist or cybersecurity attacks,
including nation-state attacks or organized cybercrime and other catastrophic events and (d) the passage of time and normal
wear and tear. Further, our ability to successfully and timely complete routine maintenance or other capital projects at our
existing facilities is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful,
we could be subject to additional costs or losses and write downs of our investment in the project.
We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety
laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs. The unexpected
requirement of large capital expenditures could have a material adverse effect on us. Moreover, if we significantly modify a
unit, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as
such terms are defined under the new source review provisions of the CAA, which would likely result in substantial additional
capital expenditures.
In addition, unplanned outages at any of our generation facilities, whether because of equipment breakdown or otherwise,
typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or
non-performance penalties or require us to incur significant costs as a result of running one of our higher cost units or to
procure replacement power at spot market prices in order to fulfill contractual commitments. If we do not have adequate
liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant
opportunities and may have increased exposure to the volatility of spot markets, which could have a material adverse effect on
us. Further, our inability to operate our generation facilities efficiently, manage capital expenditures and costs, and generate
earnings and cash flows from our asset-based businesses could have a material adverse effect on our results of operations,
financial condition or cash flows. While we maintain insurance, obtain warranties from vendors and obligate contractors to
meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to
cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or
non-performance by contractors or vendors.
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could
have a material adverse effect on our revenues and results of operations, and we may not have adequate insurance to cover
these risks and hazards. Our employees, contractors, customers and the general public may be exposed to a risk of injury
due to the nature of our operations.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large
pieces of equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as
extreme weather, earthquake, flood, lightning, hurricane and wind, other human-made hazards, such as nuclear accidents, dam
failure, gas or other explosions, mine area collapses, fire, structural collapse, machinery failure, and other dangerous incidents
are inherent risks in our operations. These and other hazards have and may in the future cause significant personal injury or loss
of life, severe damage to and destruction of property, plant, and equipment, contamination of, or damage to, the environment
and suspension of operations. Further, our employees and contractors work in, and customers and the general public may be
exposed to, potentially dangerous environments at or near our operations. As a result, employees, contractors, customers, and
the general public are at risk for serious injury, including loss of life.
38

The occurrence of any one of these events has in the past and may in the future result in us being named as a defendant in
lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property
damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot
provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or
liabilities to which we may be subject and, even if we do have insurance coverage for a particular circumstance, we may be
subject to a large deductible and maximum cap. A successful claim for which we are not fully insured could hurt our financial
results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets,
including increasing pressure on firms that provide insurance to companies that own and operate fossil fuel generation, we
cannot provide any assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to
those presently available. Any losses not covered by insurance could have a material adverse effect on our financial condition,
results of operations or cash flows.
We have been and may in the future be materially and adversely affected by obligations to comply with federal and state
regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, corrective action,
disposal and monitoring relating to CCR.
As a result of electricity produced for decades at coal-fueled power plants in Illinois, Texas and Ohio, we manage large
amounts of CCR material in surface impoundments. In addition to the federal requirements under the CCR rule, CCR surface
impoundments will continue to be regulated by existing state laws, regulations and permits, as well as additional legal
requirements that may be imposed in the future. These federal and state laws, regulations and other legal requirements may
require or result in additional expenditures, increased operating and maintenance costs and/or result in closure of certain power
generation facilities, which could affect the results of operations, financial position and cash flows of the Company. We have
recognized ARO liabilities related to these CCR-related requirements based on costs of closure methods that our operations and
environmental services teams determined were appropriate based on the existing closure requirements at the time we recorded
those ARO liabilities, and is reasonably possible for those to increase once the IEPA determines final closure requirements for
our Illinois sites. As the closure and CCR management work progresses and final closure plans and corrective action measures
are developed and approved at each site, the scope and complexity of work and the amount of CCR material could be greater
than current estimates and could, therefore, materially impact earnings through increased compliance expenditures.
The EPA was directed by the Biden Administration to review a number of environmental rules adopted by the EPA during
the first Trump Administration, including the CCR rule, the ELG rule, the ACE rule and the particulate matter (PM), and
NAAQS rules. All of these rules may significantly and adversely impact our existing coal fleet and may lead to accelerated
plant closure timeframes. In addition, the new GHG rule and the PM2.5 NAAQS rule finalized in 2024 along with other
NAAQS that may be issued in the future have the potential to adversely impact our natural gas-fired units. In January 2025,
President Trump issued an executive Order, which among other things, requires the EPA to review many of the rules issued by
the Biden Administration and further instructed that the U.S. Attorney General may request a stay of the litigation while the
EPA conducts its review.
The EPA is reviewing applications submitted by us to extend closure deadlines for many of our CCR impoundments. The
scope and cost of that closure work could increase significantly based on new or potential requirements imposed by the EPA or
state agencies, including the EPA's interpretations on requirements for closure of CCR units. There is no assurance that our
current assumptions for closure activities will be accepted by the EPA or state agencies. If ponds must be closed sooner than
anticipated, plant closures timeframes may be accelerated.
The availability and cost of emission allowances could adversely impact our costs of operations.
We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2, CO2, and
NOX to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to
meet the obligations imposed on us by various applicable environmental laws. If our operational needs require more than our
allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are
unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as
not to exceed our available emission allowances or install costly new emission controls. As we use the emission allowances that
we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such
allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially
increase our costs of operations in the affected markets.
39

We have been and may in the future be materially and adversely affected by the effects of extreme weather conditions and
seasonality.
We have been and may in the future be materially affected by weather conditions and our businesses may fluctuate
substantially on a seasonal basis as the weather changes. In addition, we are subject to the effects of extreme weather
conditions, including sustained or extreme cold or hot temperatures, hurricanes, floods, droughts, storms, fires, earthquakes or
other natural disasters, which could stress our generation facilities and grid reliability, limit our ability to procure adequate fuel
supply, or result in outages, damage or destroy our assets and result in casualty losses that are not ultimately offset by insurance
proceeds, and could require increased capital expenditures or maintenance costs, including supply chain costs.
Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or
damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, certain
extreme weather events have previously affected, and may in the future, affect, the availability of generation and transmission
capacity, limiting our ability to source or deliver power where it is needed or limit our ability to source fuel for our plants,
including due to damage to rail or natural gas pipeline infrastructure. Additionally, extreme weather has resulted, and may in
the future result, in (i) unexpected increases in customer load, requiring our retail operation to procure additional electricity
supplies at wholesale prices in excess of customer sales prices for electricity, (ii) the failure of equipment at our generation
facilities, (iii) a decrease in the availability of, or increases in the cost of, fuel sources, including natural gas, diesel and coal, or
(iv) unpredictable curtailment of customer load by the applicable ISO/RTO in order to maintain grid reliability, resulting in the
realization of lower wholesale prices or retail customer sales. For example, Winter Storm Uri in February 2021 had a material
impact on our results of operations.
Additionally, climate change may produce changes in weather or other environmental conditions, including temperature
or precipitation levels, and thus may impact consumer demand for electricity. In addition, the potential physical effects of
climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our
operations and cause us to incur significant costs to prepare for or respond to these effects.
Weather conditions, which cannot be reliably predicted, could have adverse consequences by requiring us to seek
additional sources of electricity when wholesale market prices are high or to sell excess electricity when market prices are low,
as well as significantly limiting the supply of, or increasing the cost of our fuel supply, each of which could have a material
adverse effect on our business, results of operations, financial condition and liquidity.
Events outside of our control, including an epidemic or outbreak of an infectious disease may materially adversely affect our
business.
We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could
significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or
other communicable disease, or any other public health crisis may cause disruptions to our business and operational plans, as a
result of a number of factors, including (a) a protracted slowdown of broad sectors of the economy, (b) changes in demand or
supply for commodities, (c) significant changes in legislation or regulatory policy to address the pandemic (including
prohibitions on certain marketing channels, moratoriums or conditions on disconnections or limits or restrictions on late fees),
(d) reduced demand for electricity (particularly from commercial and industrial customers), (e) increased late or uncollectible
customer payments, (f) negative impacts on the health of our workforce, (g) a deterioration of our ability to ensure business
continuity (including increased vulnerability to cyber and other information technology risks), and (h) the inability of the
Company's contractors, suppliers, and other business partners to fulfill their contractual obligations.
40

Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the value of
our business, introduce new or emerging risks, and may otherwise have a material adverse effect on us.
If we cannot adopt technological developments on a timely basis, demand for our services may decline, or we may face
challenges in implementing or evolving our business strategy. Significant technological changes continue to impact our
industry. To grow and remain competitive, we will need to adapt to changes in available technology like generative AI,
continually invest in our assets, increase generation capacity, increase our use of low-carbon technologies, enhance our existing
offerings, and introduce new offerings to meet our current and potential customers’ changing service demands. Competitors
may incorporate new technologies into their businesses, services, and products more quickly or more successfully than we do.
Adopting new and sophisticated technologies may result in implementation issues, such as scheduling and supplier delays,
unexpected or increased costs, technological constraints, regulatory issues, customer dissatisfaction, and other issues that could
cause delays in launching new technological capabilities. This, in turn could result in significant costs or reduce the anticipated
benefits of the technology change. As we adopt new technologies, like AI, there is a risk that the content, analyses,
recommendations, or judgments that AI applications assist in producing are alleged to be deficient, inaccurate, biased, or
infringe on other’s rights or property interests. Our new services could fail to retain or gain acceptance in the marketplace, or
costs associated with these services could be higher than anticipated. As such, our adoption of technology or failure to adopt
technology could have a material adverse effect on our business, brand, financial condition, business strategy, and operating
results.
Technological advances have improved, and are likely to continue to improve, for existing and alternative methods to
produce and store power, including natural gas turbines, wind turbines, fuel cells, hydrogen, micro turbines, photovoltaic (solar)
cells, batteries, concentrated solar thermal devices, novel nuclear technologies (including small modular reactors), geothermal
energy (including enhanced geothermal systems and advanced geothermal systems), and long duration energy storage, along
with improvements in traditional technologies. Such technological advances may be superior to, or may not be compatible with,
some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to
remain competitive, and have resulted, and are expected to continue to reduce the costs of power production or storage, which
may result in the obsolescence of certain of our operating assets. Consequently, the value of our more traditional generation
assets could be significantly reduced as a result of these competitive advances, which could have a material adverse effect on us
and our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer
services and products that meet customer demands and evolving industry standards. In addition, changes in technology have
altered, and are expected to continue to alter, the channels through which retail customers buy electricity (i.e., self-generation or
distributed-generation facilities). To the extent self-generation or distributed generation facilities become a more cost-effective
option for customers, our financial condition, operating cash flows and results of operations could be materially and adversely
affected.
Technological advances in demand-side management, large-scale residential or commercial virtual power plants, and
increased conservation efforts could result in a decrease in electricity demand. A significant decrease in electricity demand as a
result of such efforts would significantly reduce the value of our generation assets. Certain regulatory and legislative bodies
have introduced or are considering requirements and/or incentives to reduce power consumption. Effective power conservation
by our customers could result in reduced electricity demand or significantly slow the growth in such demand. Any such
reduction in demand could have a material adverse effect on us. Furthermore, we may incur increased capital expenditures if we
are required to increase investment in conservation measures. Additionally, increased governmental and consumer focus on
energy sustainability efforts, including desire for, or incentives related to, the development, implementation and usage of low-
carbon technology, may result in decreased demand for the traditional generation technologies that we currently own and
operate.
We may potentially be affected by emerging technologies that may over time affect change in capacity markets and the
energy industry overall including distributed generation and clean technology.
Some of these emerging technologies are distributed renewable energy technologies, energy efficiency, broad consumer
adoption of electric vehicles, distributed generation, energy storage devices, fuel cells, nuclear small modular reactors, and
linear generators. Additionally, large-scale cryptocurrency mining, AI data centers, and increased industrial electrification are
becoming increasingly prevalent in certain markets, including ERCOT, and many of these facilities are "behind-the-meter."
Such emerging technologies could affect the price of energy, levels of customer-owned generation, customer expectations and
current business models and make portions of our electric system power supply and transmission and/or distribution facilities
obsolete prior to the end of their useful lives. These emerging technologies may also affect the financial viability of utility
counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse
effect on our financial condition, results of operations and cash flows could be materially adversely affected.
41

The loss of the services of our "key" management and personnel could adversely affect our ability to successfully operate
our businesses.
Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for
such personnel with many other companies, in and outside of our industry, government entities and other organizations.
Potential difficulties in attracting and retaining highly qualified, skilled employees could restrict our ability to adequately
support our business needs and/or result in increased personnel costs. In addition, effective succession planning is important to
our long-term success. Failure to timely and effectively ensure transfer of knowledge and smooth transitions involving senior
management and other key personnel could hinder our strategic planning and execution.
We could be materially and adversely impacted by strikes or work stoppages by our unionized employees.
As of December 31, 2024, we had approximately 1,940 employees covered by collective bargaining agreements. The
terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations,
lignite-, coal-, natural gas- and nuclear-fueled generation operation, as well as some battery operations, expire on various dates
between February 2025 and March 2028, but remain effective thereafter unless and until terminated by either party. In the event
that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or
disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or
outages. We have in place strike contingency plans that address the procurement of replacement labor. Strikes, work stoppages
or the inability to negotiate current or future collective bargaining agreements on favorable terms or at all could have a material
adverse effect on us.
Risks Related to Our Structure and Ownership of our Common Stock
Vistra is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to existing and
future liabilities of its subsidiaries.
Vistra is a holding company that does not conduct any business operations of its own. As a result, Vistra's cash flows and
ability to meet its obligations are largely dependent upon the operating cash flows of Vistra's subsidiaries and the payment of
such operating cash flows to Vistra in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate
and distinct legal entities from Vistra and have no obligation (other than any existing contractual obligations) to provide Vistra
with funds to satisfy its obligations. Any decision by a subsidiary to provide Vistra with funds to satisfy its obligations, whether
by dividends, distributions, loans or otherwise, will depend on, among other things, such subsidiary's results of operations,
financial condition, cash flows, cash requirements, contractual prohibitions and other restrictions, applicable law and other
factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair
its ability to pay dividends or make other distributions to Vistra.
Evolving expectations from stakeholders, including investors, on ESG issues, including climate change and sustainability
matters, and erosion of stakeholder trust or confidence could influence actions or decisions about our company and our
industry and could adversely affect our business, operations, financial results or stock price.
Companies across all industries are facing evolving expectations or increasing scrutiny from stakeholders related to their
approach to ESG matters. For Vistra, reliability, affordability, safety, climate change, and stakeholder relations remain primary
focus areas, and changing expectations of our practices and performance across these and other ESG areas may impose
additional costs or create exposure to new or additional risks. Our operations, projects and growth opportunities require us to
have strong relationships with key stakeholders, including local communities and other groups directly impacted by our
activities, as well as governments and government agencies, investor advocacy groups, certain institutional investors,
investment funds and others which are increasingly focused on sustainability practices. Certain financial institutions have
announced policies to presently or in the future cease investing or to divest investments in companies that derive any or a
specified portion of their income from, or have any or a specified portion of their operations in, coal and/or other fossil fuels.
42

We are strategically focused on meeting growing demand for electricity as we ensure reliability and affordability while
being mindful of growing stakeholder interest in our plans to transition to low-to-no carbon power generation sources. As we
work through this transition, our prioritization of reliability and affordability may prevent us from achieving our targets as
expected, which could impact stakeholder trust and confidence. Any such erosion of stakeholder trust and confidence, evolving
expectations from stakeholders on such ESG issues, and such parties' resulting actions or decisions about our company and our
industry could have negative impacts on our business, operations, financial results, and stock price, including:
•
negative stakeholder sentiment toward us and our industry, including concerns over environmental or sustainability
matters and potential changes in federal and state regulatory actions related thereto;
•
loss of business or loss of market share, including to competitors who do not have any, or comparable amounts, of
operations involving fossil fuels;
•
loss of ability to hire and retain top talent;
•
loss of ability to secure growth opportunities;
•
the inability to, or increased difficulties and costs of, obtaining services, materials, or insurance from third parties;
•
reductions in our credit ratings or increased costs of, or limited access to, capital;
•
delays in project execution;
•
legal action;
•
increased regulatory oversight;
•
impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
•
changing investor sentiment regarding investment in the power and utilities industry or our company; and
•
restricted access to and cost of capital.
We may not pay any dividends on our common stock in the future, and we may not realize the anticipated benefits of our
share repurchase program.
The Board has adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the
program will be subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of
any such declaration including, but not limited to, prevailing market conditions, our results of operations, financial condition
and liquidity, contractual prohibitions and other restrictions with respect to the payment of dividends. There is no assurance that
the Board will declare, or that we will pay, any dividends on our common stock in the future.
The Board has approved a share repurchase program in an aggregate authorized amount of $6.75 billion. Under this share
repurchase program or any other future share repurchase programs, we may make share repurchases through a variety of
methods, including open share market purchases or privately negotiated transactions. The timing and amount of repurchases, if
any, will depend on factors such as the stock price, economic and market conditions, and corporate and regulatory
requirements. Any failure to repurchase shares after we have announced our intention to do so may negatively impact our
reputation, investor confidence and the price of our common stock.
Holders of our preferred stock may have interests and rights that are different from our common stockholders.
We are permitted under our certificate of incorporation to issue up to 100,000,000 shares of preferred stock. We can issue
shares of our preferred stock in one or more series and can set the terms of the preferred stock without seeking any further
approval from our common stockholders. Any preferred stock that we issue may rank ahead of our common stock in terms of
dividend priority or liquidation premiums and may have greater voting rights than our common stock, which could dilute the
value of our common stock to current stockholders and could adversely affect the market price of our common stock. As of
December 31, 2024, 1,000,000 shares of Series A Preferred Stock, 1,000,000 shares of Series B Preferred Stock, and 476,081
shares of Series C Preferred Stock were issued and outstanding. The Preferred Stock represents a perpetual equity interest in the
Company and, unlike our indebtedness, will not give rise to a claim for payment of a principal amount at a particular date;
provided, the Company may redeem the Preferred Stock at the specified times (or upon certain specified events) at the
applicable redemption price set forth in the certificate of designation of each of the Series A Preferred Stock, Series B Preferred
Stock, and Series C Preferred Stock, respectively (Certificates of Designation). The Preferred Stock is not convertible into or
exchangeable for any other securities of the Company. Upon the liquidation, dissolution or winding up of the Company,
whether voluntary or involuntary, after payment or provision for payment of the debts and other liabilities of the Company, the
holders of Preferred Stock will be entitled to receive, pro rata and in preference to the holders of any other capital stock, an
amount per share equal to $1,000 plus accrued and unpaid dividends thereon, if any.
43

Unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A
Preferred Stock, the holders of at least two-thirds of the outstanding Series B Preferred Stock and the holders of at least two-
thirds of the outstanding Series C Preferred Stock, each voting as a separate class, we may not adopt any amendment to our
certificate of incorporation (including the applicable Certificates of Designation) that would have a material adverse effect on
the powers, preferences, duties, or special rights of such series of Preferred Stock, subject to certain exceptions. In addition,
unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A
Preferred Stock, the holders of at least two-thirds of the outstanding Series B Preferred Stock and the holders of at least two-
thirds of the outstanding Series C Preferred Stock, voting as a class together with the holders of any parity securities upon
which like voting rights have been conferred and are exercisable, we may not: (i) create or issue any senior securities, (ii) create
or issue any parity securities (including any additional Preferred Stock) if the cumulative dividends payable on the outstanding
Preferred Stock (or parity securities, if applicable) are in arrears; (iii) create or issue any additional Preferred Stock or any parity
securities with an aggregate liquidation preference, together with the issued and outstanding Preferred Stock and any parity
securities that are then outstanding, of greater than $2.5 billion, and (iv) engage in any Transaction that results in a Covered
Disposition (as such terms are defined in the Certificates of Designation).
In addition, holders of the Preferred Stock are entitled to receive, when, as, and if declared by our Board, semi-annual
cash dividends on the Preferred Stock, which are cumulative from the applicable initial issuance date of the Preferred Stock and
payable in arrears, and unless full cumulative dividends have been or contemporaneously are being paid or declared on the
Preferred Stock, we may not (i) declare or pay any dividends on any junior securities, including our common stock, or (ii)
redeem or repurchase any parity securities or junior securities, subject to limited exceptions set forth in the Certificates of
Designation. There is no assurance that the Board will declare, or that we will pay, any dividends on our Preferred Stock in the
future. The holders of Preferred Stock (along with any parity securities then outstanding with similar rights) are entitled to elect
two additional directors in the event any dividends on Preferred Stock are in arrears for three or more semi-annual dividend
periods (whether or not consecutive), and such directors may have competing and different interests to those elected by our
common stockholders. The dividend rate for the Series A Preferred Stock from and including the initial issuance date of
October 15, 2021 until the first reset date of October 15, 2026 will be 8.0% per annum of the $1,000 liquidation preference per
share of Series A Preferred Stock. The dividend rate for the Series B Preferred Stock from and including the initial issuance
date of December 10, 2021 until the first reset date of December 15, 2026 will be 7.0% per annum of the $1,000 liquidation
preference per share of Series B Preferred Stock. The dividend rate for the Series C Preferred Stock from and including the
initial issuance date of December 29, 2023 until the first reset date of January 15, 2029 will be 8.875% per annum of the $1,000
liquidation preference per share of Series C Preferred Stock. On and after the first reset date of the Series A Preferred Stock, the
dividend rate on the Series A Preferred Stock for each subsequent five-year period (each, a Reset Period) will be adjusted based
upon the applicable Treasury rate, plus a spread of 6.93% per annum; provided that the applicable Treasury rate for each Reset
Period will not be lower than 1.07%. On and after the first reset date of the Series B Preferred Stock, the dividend rate on the
Series B Preferred Stock for each Reset Period will be adjusted based upon the applicable Treasury rate, plus a spread of 5.74%
per annum; provided that the applicable Treasury rate for each Reset Period will not be lower than 1.26%. On and after the first
reset date of the Series C Preferred Stock, the dividend rate on the Series C Preferred Stock for each Reset Period will be
adjusted based upon the applicable Treasury rate, plus a spread of 5.045% per annum; provided that the applicable Treasury
rate for each Reset Period will not be lower than 3.830%. In the event that the Company does not exercise its option to redeem
all the shares of Preferred Stock within 120 days after the first date on which a Change of Control Trigger Event (as defined in
the Certificate of Designation) occurs, the then-applicable dividend rate for the Preferred Stock will be increased by 5.00%.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
44

Item 1C. CYBERSECURITY
The Company has a cybersecurity and incident response program designed to assess, identify, and manage material risks
from cybersecurity threats, including matters related to the cybersecurity of the Company's critical infrastructure, data, or
information technology systems and the Company's actions to prepare for, identify, assess, respond, mitigate and remediate
material cyber, information security, or technology risks (collectively referred to as Information Security). This program
includes:
•
operating a Cyber Security Operations Center;
•
raising employee awareness through annual general and job-specific cybersecurity trainings and employee phishing
simulations;
•
maintaining defined cyber incident response plans;
•
enhancing security measures to protect our systems and data;
•
evolving monitoring capabilities to improve early detection and rapid response to potential cyber threats; and
•
adapting to new work environments that include off-site work through mitigation of remote network risk to our
internal systems, assets, or data.
Cybersecurity represents an important component of the Company's overall approach to enterprise risk management and is
integrated into the risk management process and ongoing assessment. In addition to an internal security program, we strive to
stay ahead of the threat landscape by actively monitoring and conducting due diligence on key third-party vendors' Information
Security programs and risks. This includes qualitative assessments to gain a deeper understanding of their security posture and
potential vulnerabilities. We make strategic investments in our perimeter and internal defenses, cyber security operations center,
and regulatory compliance activities with the advice of consultants and third parties. Moreover, to minimize risk, we maintain
an insurance policy that provides coverage for matters relating to Information Security.
Vistra's Chief Information Officer (CIO) ensures Information Security is built into the Company's larger technology
strategy and oversees our Chief Information Security Officer (CISO). Our CISO and his Information Security team are
responsible for leading the enterprise-wide information security strategy, policy, standards, architecture, and processes.
Additionally, our Cyber Incident Response Teams under the CISO are responsible for monitoring and analyzing the Company's
cybersecurity posture in partnership with Risk and Legal.
The CIO and CISO collaborate with our internal audit department and external consultants to review information
technology-related risks (based upon the National Institute of Standards and Technology (NIST) Cybersecurity Framework) as
part of the overall Vistra cyber risk management process. Through these processes, the CIO and CISO are informed about and
monitor the prevention, detection, mitigation, and remediation of cybersecurity threats.
We also participate in industry groups and with regulators to gain additional knowledge, including, but not limited to, the
Federal Bureau of Investigation, U.S. Cybersecurity and Infrastructure Security Agency, U.S. Department of Homeland
Security, Electricity Information Sharing and Analysis Center, U.S. Cyber Emergency Response Team, the NRC and NERC.
We apply the knowledge gained through industry partnerships, government organizations, external cyber risk platforms, and
program maturity assessments to improve our processes to detect and mitigate cyber threats.
As of the date of this report, we have not identified any impacts from cybersecurity threats, including those from any
previous cybersecurity incidents, that have materially affected our results of operation or financial condition. However, despite
our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced
undetected cybersecurity incidents. For additional information on risks from cybersecurity threats, see Item 1A. Risk Factors.
The Sustainability and Risk Committee of the Board has been delegated oversight responsibility of Vistra's Information
Security. Vistra periodically engages third-party advisors to provide cybersecurity oversight and tabletop training to the full
Board to further our commitment to responsible oversight of cybersecurity risk management. At least quarterly, our CIO reports
to the Board on our Information Security program, including cybersecurity risks and threats (including the emerging threat
landscape), an assessment of our Information Security program, and the status of projects to strengthen our Information
Security program. In furtherance of our commitment to responsible oversight of cybersecurity risk management, in 2023, the
Board appointed a director who brings extensive cybersecurity expertise to the Board.
45

Our CIO serves as head of Vistra's Technology Services and is responsible for ensuring the reliability, security, and
continued development of the Company's technology platforms and delivering new solutions to support the business. The CIO
has served in various senior information technology roles in public companies for over 30 years, including Keurig Dr. Pepper
Inc., General Motors, Pfizer, and Electronic Data Systems.
Our CISO has over 23 years of information technology experience. He has held technology positions across various areas
— including infrastructure management, application management, architecture, operations, and cybersecurity — and brings
expertise from Farmers Insurance and Zurich Insurance.
Item 2. PROPERTIES
The following table presents our asset fleet as of December 31, 2024 by segment. All of our facilities are 100% (fee
simple) owned.
Texas Segment
Ennis
Ennis, TX
ERCOT
CCGT
Natural Gas
366
Forney
Forney, TX
ERCOT
CCGT
Natural Gas
1,912
Hays
San Marcos, TX
ERCOT
CCGT
Natural Gas
1,047
Lamar
Paris, TX
ERCOT
CCGT
Natural Gas
1,180
Midlothian
Midlothian, TX
ERCOT
CCGT
Natural Gas
1,596
Odessa
Odessa, TX
ERCOT
CCGT
Natural Gas
1,180
Wise
Poolville, TX
ERCOT
CCGT
Natural Gas
787
DeCordova
Granbury, TX
ERCOT
CT
Natural Gas
260
Morgan Creek
Colorado City, TX
ERCOT
CT
Natural Gas
390
Permian Basin
Monahans, TX
ERCOT
CT
Natural Gas
325
Graham
Graham, TX
ERCOT
ST
Natural Gas
630
Lake Hubbard
Dallas, TX
ERCOT
ST
Natural Gas
921
Stryker Creek
Rusk, TX
ERCOT
ST
Natural Gas
685
Trinidad
Trinidad, TX
ERCOT
ST
Natural Gas
244
Coleto Creek
Goliad, TX
ERCOT
ST
Coal
650
Martin Lake
Tatum, TX
ERCOT
ST
Coal
2,250
Oak Grove
Franklin, TX
ERCOT
ST
Coal
1,600
Comanche Peak (b)
Glen Rose, TX
ERCOT
Nuclear
Uranium
2,400
Brightside
Live Oak County, TX
ERCOT
Solar
Renewable
50
Emerald Grove
Crane County, TX
ERCOT
Solar
Renewable
108
Upton 2
Upton County, TX
ERCOT
Solar/Battery
Renewable
190
DeCordova
Granbury, TX
ERCOT
Battery
Renewable
260
Total Texas Segment
19,031
Facility
Location
ISO/RTO
Technology
Primary Fuel
Net Capacity
(MW) (a)
46

East Segment
Independence
Oswego, NY
NYISO
CCGT
Natural Gas
1,212
Bellingham
Bellingham, MA
ISO-NE
CCGT
Natural Gas
566
Blackstone
Blackstone, MA
ISO-NE
CCGT
Natural Gas
544
Casco Bay
Veazie, ME
ISO-NE
CCGT
Natural Gas
543
Lake Road
Dayville, CT
ISO-NE
CCGT
Natural Gas
827
Masspower
Indian Orchard, MA
ISO-NE
CCGT
Natural Gas
281
Milford
Milford, CT
ISO-NE
CCGT
Natural Gas
600
Baldwin
Baldwin, IL
MISO
Solar/Battery
Renewable
70
Coffeen
Coffeen, IL
MISO
Solar/Battery
Renewable
46
Baldwin
Baldwin, IL
MISO
ST
Coal
1,185
Newton
Newton, IL
MISO
ST
Coal
615
Kincaid
Kincaid, IL
PJM
ST
Coal
1,108
Miami Fort 7 & 8
North Bend, OH
PJM
ST
Coal
1,020
Fayette
Masontown, PA
PJM
CCGT
Natural Gas
726
Hanging Rock
Ironton, OH
PJM
CCGT
Natural Gas
1,430
Hopewell
Hopewell, VA
PJM
CCGT
Natural Gas
370
Kendall
Minooka, IL
PJM
CCGT
Natural Gas
1,288
Liberty
Eddystone, PA
PJM
CCGT
Natural Gas
607
Ontelaunee
Reading, PA
PJM
CCGT
Natural Gas
600
Sayreville
Sayreville, NJ
PJM
CCGT
Natural Gas
349
Washington
Beverly, OH
PJM
CCGT
Natural Gas
711
Calumet
Chicago, IL
PJM
CT
Natural Gas
380
Dicks Creek
Monroe, OH
PJM
CT
Natural Gas
155
Pleasants
Saint Marys, WV
PJM
CT
Natural Gas
388
Miami Fort (CT)
North Bend, OH
PJM
CT
Fuel Oil
77
Beaver Valley 1 & 2
Shippingport, PA
PJM
Nuclear
Uranium
1,872
Perry
Perry, OH
PJM
Nuclear
Uranium
1,268
Davis-Besse
Oak Harbor, OH
PJM
Nuclear
Uranium
908
Total East Segment
19,746
West Segment
Moss Landing 1 & 2
Moss Landing, CA
CAISO
CCGT
Natural Gas
1,020
Moss Landing
Moss Landing, CA
CAISO
Battery
Renewable
750
Oakland
Oakland, CA
CAISO
CT
Fuel Oil
110
Total West Segment
1,880
Total capacity
40,657
Facility
Location
ISO/RTO
Technology
Primary Fuel
Net Capacity
(MW) (a)
___________
(a) Approximate net generation capacity. Actual net generation capacity may vary based on a number of factors, including
ambient temperature. We have not included units that have been retired or are out of operation. See Note 6 to the
Financial Statements for additional information.
47

Our wholesale commodity risk management group also procures renewable energy credits from renewable generation in
ERCOT and PJM to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for
renewable resources from such customers. As of December 31, 2024, Vistra had long-term agreements to procure renewable
energy credits from approximately 950 MW of renewable generation. These renewable generation sources deliver electricity
when conditions make them available, and, when on-line, they generally compete with baseload units. Because they cannot be
relied upon to meet demand continuously due to their dependence on weather and time of day, these generation sources are
categorized as non-dispatchable and create the need for intermediate/load-following resources to respond to changes in their
output.
Item 3. LEGAL PROCEEDINGS
See Note 15 to the Financial Statements for additional information.
Item 4. MINE SAFETY DISCLOSURES
Vistra currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to provide
fuel for its electricity generation facilities. Vistra also owns or leases, and is in the process of reclaiming, two waste-to-energy
surface facilities in Pennsylvania. These mining operations are regulated by the MSHA under the Federal Mine Safety and
Health Act of 1977, as amended (the Mine Act), along with other federal and state regulatory agencies such as the RCT and
Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra's mines, on a regular basis, and if it believes a
violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order,
generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often
results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of
MSHA citations, orders, and proposed assessments are provided in Exhibit 95.1 to this annual report on Form 10-K.
48

PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Vistra's common stock is listed and traded on the NYSE under the symbol "VST". Vistra's authorized capital stock
consists of 1,800,000,000 shares of common stock with a par value of $0.01 per share.
As of February 24, 2025, there were 403 stockholders of record.
The Board has authority to declare dividends to the holders of our common stock. The Board intends to continue the
payment of dividends to the holders of the Company's common stock in the future. The declaration and payment of future
dividends, however, will be at the discretion of the Board and will depend on numerous factors in existence at the time of any
such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition
and liquidity, Delaware law and contractual limitations.
Stock Performance Graph
The performance graph below compares Vistra's cumulative total return on common stock during the five-year period
from December 31, 2019 through December 31, 2024 with the cumulative total returns of the S&P 500 Stock Index (S&P 500)
and the S&P Utility Index (S&P Utilities). The graph below compares the return in each period assuming that $100 was
invested at December 31, 2019 in Vistra's common stock, the S&P 500 and the S&P Utilities, and that all dividends were
reinvested.
Comparison of Five-Year Cumulative Total Return
Vistra Corp.
S&P 500
S&P Utilities
12/31/19
12/31/20
12/31/21
12/31/22
12/31/23
12/31/24
$0
$100
$200
$300
$400
$500
$600
$700
December 31,
2019
2020
2021
2022
2023
2024
Vistra Corp.
$
100.00
$
88.22
$
105.47
$
110.83
$
189.20
$
683.61
S&P 500
$
100.00
$
118.39
$
152.34
$
124.73
$
157.48
$
196.85
S&P Utilities
$
100.00
$
100.52
$
118.29
$
120.14
$
111.63
$
137.79
49

The stock price performance included in this graph is not necessarily indicative of future stock price performance.
Purchases of Equity Securities by the Issuer
The following table provides information about our repurchase of common stock, during the three months ended
December 31, 2024.
Period
Total Number
of Shares
Purchased
Average
Price Paid
per Share
Total Number of Shares
Purchased as Part of a
Publicly Announced
Program
Maximum Dollar Amount
of Shares that may yet be
Purchased under the
Program (in millions)
October 1 - October 31, 2024
464,487
$
126.99
464,487
$
2,177
November 1 - November 30, 2024
425,674
$
144.66
425,674
$
2,115
December 1 - December 31, 2024
735,536
$
144.52
735,536
$
2,009
For the quarter ended December 31, 2024
1,625,697
$
139.55
1,625,697
$
2,009
In October 2021, the Board authorized a share repurchase program (Share Repurchase Program). Under this program,
shares of the Company's common stock may be repurchased in open market transactions, privately negotiated transactions, or
other means in accordance with federal securities laws. The timing, number, and value of shares repurchased will be determined
at our discretion, considering factors such as capital allocation priorities, stock market price, general market and economic
conditions, legal requirements, and compliance with debt agreements and preferred stock certificates of designation. We expect
to complete repurchases under the Share Repurchase Program by the end of 2026.
Amount Authorized
for Share
Repurchases
(in billions)
Board Authorization Dates:
October 2021
$
2.00
August 2022
1.25
March 2023
1.00
February 2024
1.50
October 2024
1.00
Cumulative authorization at
December 31, 2024
$
6.75
See Note 16 to the Financial Statements for additional information.
Item 6. [RESERVED]
Not applicable.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, AND RESULTS OF
OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read together with the
consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data. See Item
7. Management's Discussion and Analysis of Financial Condition, and Results of Operations in our 2023 Form 10-K for a
discussion of our financial condition and results of operations for the year ended December 31, 2022 and for the year ended
December 31, 2023 compared to the year ended December 31, 2022, which is incorporated here by reference. The Sunset
segment was eliminated in the fourth quarter of 2024, resulting in the recast of results for four coal facilities to the East segment
and one coal facility to the Texas segment (see Note 19 to the Financial Statements). The recast is reflected in the results of
operations for the years ended December 31, 2024 and 2023. The re-segmentation did not result in a material change in the
reported results for the East and Texas segments for the year ended December 31, 2023 compared to the year ended
December 31, 2022.
50

Significant Activities and Events, and Items Influencing Future Performance
Merger with Energy Harbor
On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i)
Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary
of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly-owned subsidiary of Vistra Vision, and
(iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue) exchanged a
portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively,
Energy Harbor Merger). The Energy Harbor Merger combined Energy Harbor's and Vistra's nuclear and retail businesses and
certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free
technologies (dispatchable and renewables/storage) and the retail business. The cash consideration for Energy Harbor Merger
was funded by Vistra Operations using a combination of cash on hand and borrowings under the Commodity-Linked Facility,
the Receivables Facility and the Repurchase Facility. See Note 2 to the Financial Statements.
Acquisition of Noncontrolling Interest
On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect
subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (as amended, the
UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings agreed to purchase each of Nuveen's and
Avenue's combined 15% noncontrolling interest in Vistra Vision for approximately $3.2 billion in cash (collectively, the
Transaction). The Transaction closed on December 31, 2024 (the Closing Date) and Vistra Vision Holdings now owns 100% of
the equity interests in Vistra Vision. See Note 9 to the Financial Statements.
Nuclear Plant License Renewals
In July 2024, our application for license renewal at our two-unit Comanche Peak Nuclear Plant was approved by the NRC.
The licenses for Units 1 and 2 now extend into 2050 and 2053, respectively, an additional 20 years beyond our original licenses.
In 2023, the Perry Nuclear Plant filed a license extension application to operate through 2046, an additional 20 years
beyond the existing license. A decision from the NRC is expected in late 2025.
Planned Gas-Fueled Dispatchable Power in ERCOT
In May 2024, we announced our intention to add up to 2,000 MW of dispatchable, natural gas-fueled electricity capacity
in west, central, and north Texas consisting of the following projects:
•
Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the
increasing power needs of the region, including the state's oil and gas industry.
•
Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA
rules, as a natural-gas fueled plant with up to 600 MW of capacity.
•
Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and
100 MW of winter capacity.
Our announced plan is based on market reforms that policymakers passed in the 2023 Texas legislative session, which
ERCOT and the PUCT are currently implementing. These market reforms are focused on grid reliability and proper market
signals. If successfully implemented, they could offer the regulatory framework necessary for Vistra to confidently make the
long-term investments in these capacity projects. In addition, in July 2024, we filed applications with the PUCT under the
Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced
above. In August 2024, the PUCT notified Vistra that an application for one of its west Texas advanced simple-cycle peaking
plants was selected for due diligence as part of the Texas Energy Fund loan program, which is ongoing. Vistra's other
application for a second west Texas gas plant remains active. An invitation to due diligence does not mean an applicant is
awarded a loan. Vistra's decision to move forward with the new west Texas gas plant project is contingent upon supportive
market reforms, approval of our Texas Energy Fund loan application, and other factors, including state and federal
environmental regulations and long-term wholesale trends that continue to support gas generation.
51

Moss Landing 300 Battery and Martin Lake Unit 1 Updates
In January 2025, a fire occurred at our Moss Landing 300 MW battery energy storage facility in CAISO. We are still
investigating the cause and impacts, but expect to write off approximately $400 million of plant value to depreciation expense
in the first quarter of 2025, representing the facility's remaining net book value. Moss Landing 300 is part of the Moss Landing
complex, which includes two other battery facilities and a gas plant, with an aggregate book value of approximately $1 billion
including Moss Landing 300. While the gas plant is operational, the other two battery facilities remain offline as we investigate
the fire. Additional costs incurred from the events include loss of revenue from the facilities being offline, and may include
litigation costs and penalties under contracts. We will continue to assess if a triggering event has occurred to evaluate
impairment for the other complex assets.
On November 27, 2024, we experienced a fire at Unit 1 of our Martin Lake facility in ERCOT, an 815 MW unit. The
depreciation expense associated with the damaged property was less than $1 million. We currently expect the unit to return to
service in June 2025.
We expect to recover a significant portion of the direct losses incurred from each event through property damage
insurance and business interruption insurance. However, given uncertainty in timing of recoveries and potential indirect impacts
to other facilities, we cannot predict the net impact these events will have on our results of operations for 2025.
Inflation Reduction Act of 2022 (IRA)
In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy
tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC,
and a first-time stand-alone battery storage investment tax credit. The IRA also implements a 15% corporate alternative
minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section
45U nuclear PTC is available to existing nuclear facilities from 2024 through 2032 and provides a federal tax credit of up to
$15 per
MWh, subject to phase out as power prices increase above $25 per MWh (each subject to annual inflation
adjustments). The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within
International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance. As
discussed in Note 4, we recognized transferable nuclear PTC revenues of $545 million in the year ended December 31, 2024.
Treasury regulations are expected to further define the scope of the legislation in many important respects, including critical
guidance interpreting the nuclear PTC. This guidance could have a material impact on our estimate and would be reflected as a
change in estimate in the period in which the guidance is received. We do not expect Vistra to be subject to the CAMT in the
2024 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess
of $1 billion. We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in
our immediate development pipeline into account when forecasting cash taxes.
Financial and Operating Performance
The following are financial and operating highlights we achieved in the execution of our four strategic priorities:
Long-term, attractive earnings profile through the integrated business model.
•
We continued to execute our integrated business model through exceptional operational performance by capitalizing
on market opportunities that drove strong earnings for the year ended December 31, 2024. This highlights our
competitive advantage of coupling retail with our reliable and efficient generation fleet and wholesale commodity risk
management capabilities, which reduces the effects of commodity price movements and contributes to the stability
and predictability of our cash flows.
•
Our commercial team focused on effectively and efficiently managing risk by opportunistically hedging and
optimizing our assets and business positions, which led to strong plant operating performance and energy margins.
•
Our retail brands served the retail electricity and natural gas needs of end-use residential, small business, and
commercial and industrial electricity customers through multiple sales and marketing channels with products and
solutions that differentiates Vistra from our competitors.
Disciplined capital allocation.
•
During the year ended December 31, 2024, we paid dividends to common stockholders totaling $305 million.
52

•
In February 2024 and October 2024, the Board authorized incremental amounts of $1.5 billion and $1.0 billion,
respectively, under our stock repurchase program established in October 2021. During the year ended December 31,
2024, we repurchased 16.6 million shares for $1.2 billion under the program. Through February 24, 2025, total shares
repurchased under the program totaled 160 million shares for $4.9 billion, and we have $1.9 billion available for
additional repurchases under the program (see Note 16 to the Financial Statements).
Maintaining a resilient balance sheet.
•
We further diversified our sources of liquidity and improved associated borrowing costs and credit terms through a
number of enhancements and amendments to our facilities throughout the year, including (i) the expansion and
extension of both our Revolving Credit Facility (expanded by $265 million and extended to 2029) and our
Commodity-Linked Facility (expanded facility limit by $175 million and extended to October 2025), (ii) amending
both the Vistra Operations Term Loan B-3 Facility and the Vistra Zero Term Loan B Facility to reduce the fixed
spread interest by 25 and 75 basis points, respectively, (iii) establishing a $500 million alternative letter of credit
facility, and (iv) expanding and extending the Receivables Facility (expanded the purchase limit by $250 million and
extended to July 2025).
•
In April 2024, we issued $500 million of 6.000% senior secured notes due 2034 and $1.0 billion of 6.875% senior
unsecured notes due 2032. The net proceeds from these issuances were used to refinance senior secured debt
maturities in May 2024 and July 2024 and for general corporate purposes.
•
In December 2024, we issued $500 million of 5.050% senior secured notes due 2026 and $750 million of 5.700%
senior secured notes due 2034. The net proceeds from these issuances were or will be used for general corporate
purposes, including to refinance senior secured debt maturities in May 2025 and payments associated with the
Transaction for the purchase of the remaining interest in Vistra Vision.
•
In December 2024, we entered into the BCOP Credit Agreement to fund the development of solar generation and
battery ESS facilities in Illinois and Texas.
Strategic energy transition focused on the reliability, affordability, and sustainability of electric grid.
•
In March 2024, we completed the acquisition of Energy Harbor, adding an additional 4,048 MW of nuclear
generation to our fleet.
•
We reached commercial operations for two solar facilities totaling 112 MW of capacity at retired plant sites in Illinois
and continued development and construction activities on additional facilities in Texas and at retired or to-be-retired
plant sites in Illinois.
•
We announced plans to repower the Coleto Creek coal generation facility as a natural gas-fueled facility upon its
retirement no later than 2027.
During the year ended December 31, 2024, 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 strong plant operating performance, growth of our retail business and the effectiveness of our
comprehensive hedging strategy.
Macroeconomic Conditions
Historically, the base case assumption for U.S. electricity demand was for modest growth driven by the interplay of
growth in population, industrial activity (such as an on-shore manufacturing) and new demand sources (such as electric
vehicles), partially offset by continued advancements in energy efficiency. Multiple demand drivers such as emergence of large
load data centers and electrification of oil field operations (specifically in the Permian Basin of west Texas), are expected to
continue to accelerate load growth in the geographic regions we serve. We are in various discussions with interested
counterparties for the potential sale of power from our nuclear and gas facilities pursuant to long-term agreements to supply
large load facilities. Such potential transactions are subject to certain risks and uncertainties, including potential regulatory
review and/or approval and adverse legislative action, which could impact the timing of, and our ability to consummate, any
potential transaction.
53

The industry continues to experience supply chain constraints and labor shortages that have reduced the availability of
certain equipment and supply relevant to construction of new generation facilities, and increased (i) the lead time to procure
certain materials necessary to maintain, and (ii) the labor costs associated with maintenance activity on our natural gas, nuclear
and coal fleet. We are proactively managing the 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 and could impact the feasibility of additional projects. In
addition, we have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities
prior to future planned outages, and our Vistra Zero operational and development projects are anticipated to benefit from the
impact of the IRA. The inflationary environment continues to drive elevated interest rates, resulting in increased refinancing or
borrowing costs, including future non-recourse financing for our development projects and future refinancing expected in
connection with future debt maturities.
We continue to closely monitor developments in the Russia and Ukraine conflict, specifically with regards to, (i) sanctions
(or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and (ii)
actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. The
Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress, signed into law by President Biden, and took
effect on August 11, 2024. The PRUI Act prohibits importation of Russian uranium; however, the Department of Energy can
issue waivers (subject to decreasing annual caps) until December 31, 2027 if there is no alternate source of low-enriched
uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, passage of the PRUI Act
enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel. On November 15,
2024, the Russian Federation temporarily suspended shipments of uranium to the U.S., stating that they would grant future
export licenses on a case-by-case basis. Our 2024 and 2025 refueling plans have not been affected by the Russia and Ukraine
conflict, nor have we seen any disruption to the delivery of nuclear fuel impacting our refueling schedules. We work with a
diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance. We have nuclear fuel contracted
to support all our refueling needs through 2029. We continue to take affirmative action by building strategic inventory and
deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to
operate our nuclear facilities through potential Russian supply disruption.
Capacity Markets
PJM, NYISO, ISO-NE, MISO and CAISO ensure long-term grid reliability through monthly, semiannual, annual, and
multi-year capacity auctions or bilateral transactions where power suppliers commit to making the generation resources
available to the ISO as needed for a specific time period. We participate in these capacity market auctions and also enter into
bilateral capacity sales, and a portion of our East, and West segment revenues are impacted by the capacity auction results or
bilateral contracts. The following information summarizes the auction pricing for zones in which we operate as well as our
capacity auction and bilateral capacity sales by planning period. Performance incentive rules increase capacity payments for
those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less
than the required level.
PJM
Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each
planning year:
2024-2025
2025-2026
(average price per MW-day)
RTO zone
$
28.92
$
269.92
ComEd zone
28.92
269.92
MAAC zone
49.49
269.92
EMAAC zone
53.60
269.92
ATSI zone
28.92
269.92
DEOK zone
96.24
269.92
DOM zone
28.92
444.26
54

Our capacity sales in PJM, net of purchases, aggregated by planning year and capacity type through planning year
2025-2026, are as follows:
East Segment
2024-2025
2025-2026
CP auction capacity sold, net (MW)
9,935
10,255
Bilateral capacity sold, net (MW)
2,127
330
Total segment capacity sold, net (MW)
12,062
10,585
Average price per MW-day
$
41.38
$
267.12
NYISO
The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence
plant clears, are as follows for each planning period:
Winter
2024 - 2025
Price per kW-month
$
2.00
Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through
bilateral trades. Our capacity sales, aggregated by season through winter 2026-2027, are as follows:
East Segment
Winter
2024 - 2025
Summer
2025
Winter
2025 - 2026
Summer
2026
Winter
2026 - 2027
Auction capacity sold (MW)
77
—
—
—
—
Bilateral capacity sold (MW)
943
550
268
—
—
Total capacity sold (MW)
1,020
550
268
—
—
Average price per kW-month
$
3.09
$
4.51
$
4.10
$
—
$
—
ISO-NE
The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are
as follows for each planning year:
2024-2025
2025-2026
2026-2027
2027-2028
Price per kW-month
$
2.61
$
2.59
$
2.59
$
3.58
We continue to market and pursue longer term multi-year capacity transactions that extend through planning year
2027-2028.
East Segment
2024-2025
2025-2026
2026-2027
2027-2028
Auction capacity sold (MW)
3,221
3,032
2,960
3,261
Bilateral capacity sold (MW)
78
78
58
8
Total capacity sold (MW)
3,299
3,110
3,018
3,269
Average price per kW-month
$
3.10
$
2.72
$
2.60
$
3.58
MISO
The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each
planning year:
2024-2025
Price per MW-day
$
20.08
55

MISO capacity sales through planning year 2027-2028 are as follows:
East Segment
2024-2025
2025-2026
2026-2027
2027-2028
Auction capacity sold (MW)
1,095
—
—
—
Bilateral capacity sold (MW)
682
891
515
24
Total MISO segment capacity sold (MW)
1,777
891
515
24
Average price per kW-month
$
3.02
$
4.52
$
4.44
$
4.96
CAISO
Our capacity sales as part of the California Public Utilities Commission Resource Adequacy (RA) Program in California,
aggregated by calendar year for 2025 through 2028 for Moss Landing, are as follows:
West Segment
2025
2026
2027
2028
Bilateral capacity sold (Avg MW)
1,816
1,575
1,275
750
Electricity Prices
The price of electricity has a significant impact on our operating revenues and purchased power costs. Electricity prices
are typically set by the cost to fuel a generation facility and the amount of fuel needed to generate one unit of electricity (Heat
Rate) from the generation facility. Market Heat Rate is the implied relationship between wholesale electricity prices and the
commodity price of the marginal supplier (generally natural gas plants).
Wholesale electricity prices generally track to increases or decreases in the price of natural gas, with exceptions such as
when ERCOT power prices rise significantly during weather events as a result of the scarcity of available generation resources
relative to power demand. The price of natural gas is volatile; therefore, the costs to operate a natural gas-fueled generation
facility can be volatile as well. In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no
significant effect on the cost of generating power at our nuclear-, lignite- and coal-fueled facilities; however, all other factors
being equal, changes in natural gas prices affect our operating margins on these facilities as electricity prices generally track to
natural gas prices. Other variables that could impact electricity prices include, but are not limited to, the price of other fuels,
generation resources in the region, weather, on-going competition, emerging technologies, and macroeconomic and regulatory
factors.
The wholesale market price of electricity divided by the market price of natural gas represents the Market Heat Rate.
Market Heat Rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of
the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. Our Market Heat Rate
exposure is impacted by changes in the availability of generation resources, such as additions and retirements of generation
facilities, and mix of generation assets. For example, increasing renewable (wind and solar) generation capacity generally
depresses Market Heat Rates, particularly during periods when total demand is relatively low. However, increasing penetration
of renewable generation capacity may also contribute to greater volatility of wholesale market prices independent of changes in
the price of natural gas, given their intermittent nature.
As a result of our exposure to the variability of natural gas prices and Market Heat Rates, retail sales and hedging
activities are critical to our operating results and maintaining consistent cash flow levels. Our integrated power generation and
retail electricity business provides us opportunities to hedge our generation position utilizing retail electricity markets as a sales
channel. Our approach to managing electricity price risk focuses on the following:
•
employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial
energy-related contracts intended to partially hedge gross margins;
•
continuing focus on cost management to better withstand gross margin volatility;
•
following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the
magnitude and costs of commodity price, liquidity risk and retail demand variability; and
•
improving retail customer service to attract and retain high-value customers.
56

Critical Accounting Estimates
See Note 1 of the consolidated financial statements for a description of our accounting policies. The following is a
discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP.
Business Combinations
Determining fair values of assets acquired and liabilities assumed in the Energy Harbor Merger requires significant
estimates and judgments. We determined fair value based on the estimated price that would be received to sell an asset or paid
to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 2 to the Financial
Statements. The determination of the fair value of property, plant, and equipment contributed and acquired, as well as nuclear
decommissioning asset retirement obligations required the most significant level of estimation uncertainty.
The fair value of each power plant acquired in the Energy Harbor Merger and the fair value of the contributed nuclear
business was estimated using a combination of the income approach and the market approach. The income approach was based
on the discounted cash flow method, incorporating (i) our estimates of forecasted future growth and long-term prices of
electricity, capacity, and nuclear fuel, and (ii) financial performance including revenues, gross margins, operating expenses,
taxes, working capital, and capital asset requirements. Projected cash flows were then discounted to a present value employing a
discount rate that accounts for the estimated market weighted-average cost of capital, along with any risks unique to the subject
cash flows. These estimates are subjective in nature and require judgment to interpret market data. The market valuation
method utilized prices paid for reasonably similar assets by other purchasers in the relevant market, with adjustments relating to
physical differences in the asset as well as their locations.
See Asset Retirement Obligations (ARO) critical accounting estimate for methodology and assumptions used to estimate
the nuclear decommissioning ARO acquired in the Energy Harbor Merger.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of energy-related commodities, as well as other derivative instruments
such as options, swaps, futures, and forwards, primarily to manage commodity price and interest rate risks. Under accounting
standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting,
and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.
Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as
market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income
with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the
type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. Where quoted market prices are
not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative instruments valued
based on unobservable inputs primarily include (i) forward sales and purchases of electricity (including certain retail contracts),
natural gas and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights. In computing fair value
for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery
point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading
activity. For illiquid periods, fair value is estimated based on forward price curves developed using proprietary modeling
techniques that take into account available market information and other inputs that might not be readily observable in the
market. Any significant changes to these inputs could result in a material change to the value of the assets or liabilities recorded
in the consolidated balance sheets and could result in a material change to the unrealized gains or losses recorded in the
consolidated statements of operations.
Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections,
which generally eliminate the requirement for mark-to-market recognition in net income. Normal purchases and sales (NPNS)
are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal
course of business and are accounted for on an accrual basis. Determining whether a contract qualifies for the normal purchase
or sale election requires judgment as to whether or not the contract will physically deliver and requires that management ensure
compliance with all associated qualification and documentation requirements. If it is determined that a transaction designated as
a normal purchase or sale no longer meets the scope exception, the related contract would be recorded on the balance sheet at
fair value with immediate recognition through earnings.
See Notes 11 and 12 to the Financial Statements for additional information.
57

Accounting for Income Taxes
Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and
judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates
and judgments of the timing and probability of recognition of income and deductions by taxing authorities. Further, we assess
the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we
would record a valuation allowance against such deferred tax assets for the amount we would not expect to utilize, which would
reduce the carrying value of the deferred tax amounts. When evaluating the need for a valuation allowance, we consider all
available positive and negative evidence, including the following:
•
the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred
tax assets;
•
the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward;
and
•
the amounts and history of income or losses, adjusted for certain non-recurring items.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in
income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed
tax returns by taxing authorities.
Income tax returns are regularly subject to examination by applicable tax authorities. In management's opinion, the
liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be
owed as a result of any examination.
See Notes 1 and 5 to the Financial Statements for additional information.
Asset Retirement Obligations (ARO)
An ARO liability is initially recorded at fair value when it is initially incurred and the amount of the liability can be
reasonably estimated. In estimating the ARO liability, we are required to make significant estimates and assumptions. Our ARO
liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, and
remediation or closure of coal ash basins. On the Merger Date, we recognized ARO liabilities for the Beaver Valley, Perry and
Davis-Besse nuclear plants acquired from Energy Harbor.
For the estimates and assumptions of the nuclear generation plant decommissioning, we use unit-by-unit
decommissioning cost studies to provide a marketplace assessment of the expected costs and estimates of the timing of
decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and
other estimates. We consider the following decommissioning scenarios: (i) DECON, which assumes major decommissioning
activities begin shortly after the facility ceases operations, and (ii) SAFSTOR, which assumes the nuclear facility is placed and
maintained in a condition during decommissioning that allows the nuclear facility to be safely stored until subsequently
decontaminated within 60 years after the facility ceases operations. Decommissioning cost studies are updated for each of our
nuclear units at least every five years unless circumstances warrant a more frequent update. In estimating the liability assumed
in the Energy Harbor Merger, we have included an assumption that Vistra receives a license extension of 20 years from the
NRC to continue to operate the Perry Nuclear Plant through 2046.
The estimates and assumptions required for the lignite mining land reclamation include, estimates such as costs to fill in
mining pits and interpretation of the mining permit closure requirements. We estimate the costs to fill in mining pits utilizing a
proprietary model to determine the volume of the pit.
Our AROs are adjusted on a regular basis to reflect the passage of time and to incorporate revisions to estimates and
judgments including, planned plant retirement dates, amounts and timing of future cash expenditures, discount rates, cost
escalation factors, market risk premiums, inflation rates, and if applicable, experience with government regulators regarding
similar obligations.
See Note 13 to the Financial Statements for additional information.
58

Impairment of Goodwill and Other Long-Lived Assets
Goodwill and Intangible Assets with Indefinite Useful Lives
Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the our retail trade
names are not amortized and are subject to impairment testing annually, or when events or changes in the business environment
indicate that the carrying value of the reporting unit may exceed its fair value. Evaluating goodwill and intangible assets with
indefinite useful lives involves applying significant assumptions including discount rates, forecasted results for the applicable
reporting unit and retail trade name, market multiples, and growth rates. These assumptions are forward looking and could be
affected by future economic and market conditions.
Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill and
retail trade name intangible asset is more likely than not less than the fair value. If the entity determines the carrying value is
not more likely greater than the fair value, no further testing for impairment is required. On the most recent testing date, we
performed a qualitative assessment and determined that it was more likely than not that the fair value of our reporting units and
retail trade names exceeded their carrying value. Significant qualitative factors were evaluated included reporting unit and trade
name financial performance, market multiples, general macroeconomic, industry, and market conditions, cost factors, customer
attrition, and interest rates. See Note 7 to the Financial Statements for additional information.
Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in
circumstances indicate that their carrying amount may not be recoverable. Indicators of impairment for our generation facilities
include an expectation of continuing long-term declines in natural gas prices and/or Market Heat Rates, an expectation that
"more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated
useful life, or additional environmental regulations significantly decrease the cash flows expected from the associated assets.
The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature
and may require the use of estimates in forecasting future results and cash flows given the diverse fuel mix and output rates of
our generation asset groups. See Note 20 to the Financial Statements for additional information.
After identifying an indicator of impairment, recoverability of long-lived assets is determined by a comparison of the
carrying amount of the long-lived asset group to the net cash flows expected to be generated by the asset group. Assumptions
used in our estimate of net cash flows of the asset group include, forward natural gas and electricity prices, forward capacity
prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel
prices, and forecasted operating costs. The carrying value of such asset groups is determined to be unrecoverable if the
projected undiscounted cash flows are less than the carrying value.
If an asset group carrying value is determined to be unrecoverable, fair value will be calculated based on a market
participant view and a loss will be recorded for the amount the carrying value exceeds the fair value. Fair value is determined
primarily by discounted cash flows (income approach) and supported by available market valuations, if applicable. The income
approach involves estimates of future performance that reflect assumptions regarding, among other things, forward electricity
prices, forward capacity prices, Market Heat Rates, the effects of enacted environmental rules, generation plant performance,
forecasted capital expenditures, forecasted fuel prices, and the discount rate applied to the forecasted cash flows. Any
significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived
assets.
Nuclear PTC Revenues
Nuclear PTC revenues are accounted for by analogy to the grant model within International Accounting Standards 20,
Accounting for Government Grants and Disclosures of Government Assistance. Nuclear PTC revenues are based on annual
gross receipts generated from qualifying nuclear production in the calendar year. Treasury regulations are expected to further
provide interpretive guidance on the definition of gross receipts over the next year. Given the lack of guidance to date, we
recognized 2024 nuclear PTC revenues based on our best estimate and interpretation of gross receipts which includes settled
spot energy revenues and capacity revenues at each nuclear unit, and excludes any hedges. Any interpretive guidance on the
definition of gross receipts which differs from the interpretation used in our estimate could result in a material change to PTC
revenues attributable to 2024 and would be reflected as a change in estimate in the period in which the guidance is received.
59

We have determined that we will meet the prevailing wage requirements at all our nuclear units and are eligible for the
five times multiplier, which is reflected in the amount of nuclear PTC revenue recognized in 2024.
Results of Operations
Net income increased $1.32 billion to Net income of $2.812 billion for the year ended December 31, 2024 compared to
the year ended December 31, 2023. For additional information see the following discussion of our results of operations.
EBITDA and Adjusted EBITDA
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 (i) with our GAAP results and (ii) the
accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of
factors and trends affecting our business. 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.
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
the consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
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).
Vistra Consolidated Financial Results — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the year ended December 31, 2024:
(in millions)
Operating revenues
$ 12,797
$ 5,394
$ 5,661
$
877
$
1
$
(7,506) $
17,224
Fuel, purchased power costs, and delivery
fees
(10,276)
(1,596)
(2,698)
(221)
(3)
7,509
(7,285)
Operating costs
(159)
(996)
(1,103)
(72)
(81)
(3)
(2,414)
Depreciation and amortization
(114)
(581)
(996)
(86)
—
(66)
(1,843)
Selling, general, and administrative
expenses
(977)
(169)
(148)
(25)
(43)
(239)
(1,601)
Operating income (loss)
1,271
2,052
716
473
(126)
(305)
4,081
Other income
1
39
181
3
16
72
312
Other deductions
(2)
(4)
(4)
(6)
(2)
(3)
(21)
Interest expense and related charges
(54)
46
9
1
(4)
(898)
(900)
Impacts of Tax Receivable Agreement
—
—
—
—
—
(5)
(5)
Income (loss) before income taxes
1,216
2,133
902
471
(116)
(1,139)
3,467
Income tax expense
—
—
—
—
—
(655)
(655)
Net income (loss)
$ 1,216
$ 2,133
$
902
$
471
$
(116) $
(1,794) $
2,812
Income tax expense
—
—
—
—
—
655
655
Interest expense and related charges (a)
54
(46)
(9)
(1)
4
898
900
Depreciation and amortization (b)
114
686
1,278
86
—
66
2,230
EBITDA before Adjustments
1,384
2,773
2,171
556
(112)
(175)
6,597
Year Ended December 31, 2024
Retail
Texas
East
West
Asset
Closure
Eliminations /
Corporate
and Other
Vistra
Consolidated
60

Unrealized net (gain) loss resulting from
commodity hedging transactions
52
(790)
(76)
(332)
(9)
—
(1,155)
Purchase accounting impacts
—
1
(12)
—
—
(14)
(25)
Impacts of Tax Receivable Agreement
(c)
—
—
—
—
—
(5)
(5)
Non-cash compensation expenses
—
—
—
—
—
100
100
Transition and merger expenses
2
1
22
—
—
111
136
Decommissioning-related activities (d)
—
26
(91)
2
—
—
(63)
ERP system implementation expenses
8
7
5
1
2
—
23
Other, net
17
14
(2)
11
2
(111)
(69)
Adjusted EBITDA
$ 1,463
$ 2,032
$ 2,017
$
238
$
(117) $
(94) $
5,539
Year Ended December 31, 2024
Retail
Texas
East
West
Asset
Closure
Eliminations /
Corporate
and Other
Vistra
Consolidated
____________
(a) Includes $53 million of unrealized mark-to-market net gains on interest rate swaps.
(b) Includes nuclear fuel amortization of $105 million and $282 million, respectively, in the Texas and East segments.
(c) Includes $10 million gain recognized on the repurchase of TRA Rights in the year ended December 31, 2024.
(d) Represents net of all NDT (income) loss of the PJM nuclear facilities, ARO accretion expense for operating assets and
ARO remeasurement impacts for operating assets.
For the year ended December 31, 2024, the Texas and East segments include nuclear PTC revenue estimates of $281
million and $264 million, respectively. See Note 4 to the Financial Statements for additional information.
The following table presents Net income (loss), EBITDA, and Adjusted EBITDA for the year ended December 31, 2023:
(in millions)
Operating revenues
$ 10,572
$ 3,979
$ 5,890
$
914
$
—
$
(6,576) $
14,779
Fuel, purchased power costs, and delivery
fees
(9,046)
(2,028)
(2,730)
(328)
(3)
6,578
(7,557)
Operating costs
(123)
(917)
(528)
(58)
(74)
(2)
(1,702)
Depreciation and amortization
(102)
(550)
(703)
(79)
—
(68)
(1,502)
Selling, general, and administrative
expenses
(858)
(140)
(127)
(24)
(34)
(125)
(1,308)
Impairment of long-lived assets
—
—
(49)
—
—
—
(49)
Operating income (loss)
443
344
1,753
425
(111)
(193)
2,661
Other income
1
35
4
21
110
86
257
Other deductions
—
(2)
(5)
—
—
(7)
(14)
Interest expense and related charges
(20)
21
(2)
8
(5)
(742)
(740)
Impacts of Tax Receivable Agreement
—
—
—
—
—
(164)
(164)
Income (loss) before income taxes
424
398
1,750
454
(6)
(1,020)
2,000
Income tax expense
—
—
(1)
—
—
(507)
(508)
Net income (loss)
$
424
$
398
$ 1,749
$
454
$
(6) $
(1,527) $
1,492
Income tax expense
—
—
1
—
—
507
508
Interest expense and related charges (a)
20
(21)
2
(8)
5
742
740
Depreciation and amortization (b)
102
641
703
79
—
68
1,593
EBITDA before Adjustments
546
1,018
2,455
525
(1)
(210)
4,333
Unrealized net (gain) loss resulting from
commodity hedging transactions
586
813
(1,586)
(267)
(36)
—
(490)
Year Ended December 31, 2023
Retail
Texas
East
West
Asset
Closure
Eliminations /
Corporate
and Other
Vistra
Consolidated
61

Impacts of Tax Receivable Agreement (c)
—
—
—
—
—
135
135
Non-cash compensation expenses
—
—
—
—
—
78
78
Transition and merger expenses
—
1
2
—
—
47
50
Impairment of long-lived assets
—
—
49
—
—
—
49
PJM capacity performance default
impacts (d)
—
—
9
—
—
—
9
Winter Storm Uri impacts (e)
(52)
4
—
—
—
—
(48)
Other, net
25
(2)
72
5
(2)
(113)
(15)
Adjusted EBITDA
$ 1,105
$ 1,834
$ 1,001
$
263
$
(39) $
(63) $
4,101
Year Ended December 31, 2023
Retail
Texas
East
West
Asset
Closure
Eliminations /
Corporate
and Other
Vistra
Consolidated
____________
(a) Includes $36 million of unrealized mark-to-market net losses on interest rate swaps.
(b) Includes nuclear fuel amortization of $91 million in the Texas segment.
(c) Includes $29 million gain recognized on the repurchase of TRA Rights in December 2023.
(d) Represents estimate of anticipated market participant defaults or settlements on initial PJM capacity performance penalties
due to extreme magnitude of penalties associated with Winter Storm Elliott.
(e) Adjusted EBITDA impacts of Winter Storm Uri reflects 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 were expected to be paid over several decades under protocols existing at the time of the storm.
GAAP net income increased $1.32 billion to net income of $2.812 billion in the year ended December 31, 2024 compared
to the year ended December 31, 2023. The primary drivers for the increase in GAAP net income include:
Favorable impacts:
•
An increase of $665 million in unrealized mark-to-market gains on derivative positions due to power and natural gas
forward market curves moving down more significantly in Texas relative to our hedge positions in the year ended
December 31, 2024 as compared to the year ended December 31, 2023. See further information on our derivative
results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.
•
Addition of Energy Harbor in March 2024 with results reflected in the East and Retail segments.
•
An increase of $545 million in PTC revenues due to the nuclear PTC established by the IRA including $281 million
and $264 million recognized in Texas and East, respectively. See Note 4 for additional information.
•
An increase in retail income driven by an increase in customer counts and higher margins.
•
Expiration of legacy Vistra default service contracts in the East segment which resulted in higher-than-expected
migration of customers at rates below prevailing wholesale market prices in the year ended December 31, 2023.
•
A decrease of approximately $160 million of accretion and remeasurement expenses associated with the TRA
obligation driven by the acquisition of substantially all TRA rights between December 2023 and February 2024.
Unfavorable impacts:
•
Increase in depreciation and amortization expense driven by addition of assets acquired from Energy Harbor and
reflected in East.
•
Increase in interest expense driven by higher average borrowings and unrealized mark to market losses on interest
rate swaps.
•
Increase in selling, general, and administrative expenses in Retail segment and Corp. and Other driven primarily by
the addition of Energy Harbor.
•
Increase in income tax expense driven by higher income.
62

Year Ended December 31,
Retail
Texas
East
West
2024
2023
2024
2023
2024
2023
2024
2023
Retail electricity sales volumes
(GWh):
Sales volumes in ERCOT
74,295
70,275
Sales volumes in Northeast/
Midwest
59,066
27,147
Total retail electricity sales
volumes
133,361
97,422
Production volumes (GWh):
Natural gas facilities
44,595
41,849
60,279
60,502
4,175
5,462
Lignite and coal facilities
23,307
26,559
16,938
13,912
Nuclear facilities
19,670
18,893
26,540
Solar facilities
757
781
Capacity factors:
CCGT facilities
58.1 %
55.1 %
62.0 %
62.2 %
46.5 %
61.0 %
Lignite and coal facilities
59.0 %
67.4 %
49.1 %
40.4 %
Nuclear facilities
93.3 %
89.9 %
89.3 %
Weather - percent of normal
(a):
Cooling degree days
112 %
115 %
112 %
112 %
103 %
96 %
90 %
79 %
Heating degree days
78 %
85 %
77 %
88 %
88 %
87 %
119 %
125 %
____________
(a) Reflects cooling degree or heating degree days for the region based on Weather Services International (WSI) data. A
degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base
temperature.
Year Ended December 31,
Year Ended December 31,
2024
2023
2024
2023
Average Power Price
($MWh) (a):
Average Natural gas price
($/MMBtu) (b):
ERCOT North Hub
$
25.89
$
48.30
NYMEX Henry Hub
$
2.25
$
2.53
ERCOT West Hub
$
27.45
$
49.45
Houston Ship Channel
$
1.87
$
2.20
PJM AEP Dayton Hub
$
30.74
$
30.81
Permian Basin
$
0.08
$
1.53
PJM Northern Illinois Hub
$
25.46
$
26.64
Dominion South
$
1.67
$
1.63
PJM Western Hub
$
33.83
$
33.07
Tetco ELA
$
2.08
$
2.27
MISO Indiana Hub
$
31.36
$
32.98
Chicago Citygate
$
2.12
$
2.30
ISONE Massachusetts Hub
$
41.47
$
36.82
TetcoM3
$
2.07
$
1.90
New York Zone A
$
32.66
$
25.68
Algonquin Citygates
$
3.03
$
2.94
CAISO NP15
$
40.67
$
61.37
PG&E Citygate
$
3.09
$
6.09
____________
(a) Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we
realized.
(b) Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us.
63

Adjusted EBITDA for the year ended December 31, 2024 compared to the year ended December 31, 2023 increased by
$1.438 billion. The primary drivers for the increase include:
Year Ended December 31, 2024 Compared to 2023
Retail (a)
Texas
East (a)
West
(in millions)
Favorable change in realized revenue net of fuel driven by addition
of Energy Harbor, including nuclear PTC revenues from the
acquired nuclear facilities and rolloff of negative margin defaults
service contracts in East. Favorable change in Texas is driven by
nuclear PTC revenues.
$
—
$
257
$
1,570
$
6
Higher retail margins driven by favorable power supply costs,
customer count growth and addition of energy Harbor retail
contracts, including acquired default service contracts
425
—
—
—
Favorable impact of less Winter Storm Uri bill credits applied
42
—
—
—
Increase in plant operating costs due primarily to addition of
Energy Harbor in East
—
(52)
(490)
(11)
Change in SG&A and other primarily due to increase in costs
related to addition of Energy Harbor in Retail and East
(109)
(7)
(64)
(20)
Change in Adjusted EBITDA
$
358
$
198
$
1,016
$
(25)
Increase in depreciation and amortization driven primarily by
addition of Energy Harbor assets in East
(12)
(45)
(575)
(7)
Change in unrealized net gains (losses) on hedging activities (b)
534
1,603
(1,510)
65
Impairment of long-lived assets
—
—
49
—
Decommissioning related activities
—
(26)
91
(2)
PJM capacity performance default impacts
—
—
9
—
Winter Storm Uri impact
(52)
4
—
—
Other (including interest expenses)
(36)
1
73
(14)
Change in Net income
$
792
$
1,735
$
(847) $
17
___________
(a) Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024.
(b) See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.
Asset Closure Segment — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
Year Ended December 31,
Favorable
(Unfavorable)
Change
2024
2023
(in millions)
Operating revenues
$
1
$
—
$
1
Fuel, purchased power costs, and delivery fees
(3)
(3)
—
Operating costs
(81)
(74)
(7)
Selling, general, and administrative expenses
(43)
(34)
(9)
Operating loss
(126)
(111)
(15)
Other income
16
110
(94)
Other deductions
(2)
—
(2)
Interest expense and related charges
(4)
(5)
1
Income (loss) before income taxes
(116)
(6)
(110)
Net loss
$
(116) $
(6) $
(110)
Adjusted EBITDA
$
(117) $
(39) $
(78)
GAAP and Adjusted EBITDA results for the year ended December 31, 2024 are unfavorable compared to the year ended
December 31, 2023 primarily due to other income of $89 million from the gain on sale of property in Freestone County, Texas
in 2023.
64

Energy-Related Commodity Contracts and Mark-to-Market Activities
We entered the 2023 and 2024 calendar years with more than 99% of our expected generation volumes hedged. While
settled power prices in 2024 are lower than historical averages, the strategic hedging allowed us to lock in margins above what
we would have been able to realize if unhedged and are higher than the margins from hedging for the year ended December 31,
2023, which is driving the increase in realized revenue net of fuel in the generation segments along with the addition of Energy
Harbor. The forward power sales are also the drivers of the changes in unrealized gains/losses on hedging activities. As power
prices increase/decrease in comparison to what our generation segments have sold forward, the generation segments recognize
unrealized losses/gains. The retail segment procures power from the generation segments to serve future load obligations and
thus changes in forward power prices have an inverse effect on unrealized mark to market for the retail segment as compared to
the generation segments. In 2024, we saw a decrease in forward power prices in all our generation segments compared to our
hedged positions which drove material unrealized gains in those segments, partially offset by unrealized losses in our retail
segment. In 2023, the non-Texas generation segments also experienced a decrease in forward power prices compared to our
hedged positions, which resulted in unrealized gains in those segments partially offset by unrealized losses in our retail
segment. In the Texas segment, forward power prices materially increased in the year ended December 31, 2023, which resulted
in unrealized losses partially offset by unrealized gains in the Retail segment.
The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31,
2024 and 2023. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.155
billion and $490 million in unrealized net gains for the years ended December 31, 2024 and 2023, respectively, arising from
mark-to-market accounting for positions in the commodity contract portfolio.
Year Ended December 31,
2024
2023
(in millions)
Commodity contract net liability as of January 1
$
(2,740) $
(3,148)
Settlements/termination of positions (a)
1,213
1,643
Changes in fair value of positions in the portfolio (b)
(58)
(1,153)
Acquired commodity contracts (c)
(50)
—
Other activity (d)
175
(82)
Commodity contract net liability as of December 31
$
(1,460) $
(2,740)
____________
(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized
gains/(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) Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial
Statements).
(d) Primarily 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.
The following maturity table presents the net commodity contract liability arising from recognition of fair values as of
December 31, 2024, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
Maturity dates of unrealized commodity contract net liability as of December 31, 2024
Source of Fair Value
Less than
1 year
1-3 years
4-5 years
Excess of
5 years
Total
(in millions)
Prices actively quoted
$
(205)
$
11
$
(1)
$
—
$
(195)
Prices provided by other external sources
(423)
(91)
1
—
(513)
Prices based on models
(162)
(507)
(75)
(8)
(752)
Total
$
(790)
$
(587)
$
(75)
$
(8)
$
(1,460)
65

We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that
have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue
to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale
and retail electricity sales.
Estimated hedging levels for generation volumes in our Texas, East and West segments as of December 31, 2024 were as
follows:
2025
2026
Nuclear/Renewable/Coal Generation:
Texas
100 %
100 %
East
84 %
55 %
Natural Gas Generation:
Texas
100 %
57 %
East
100 %
77 %
West
100 %
37 %
Financial Condition
Cash Flows
Operating Cash Flows
Cash provided by operating activities totaled $4.563 billion and $5.453 billion for the years ended December 31, 2024 and
2023, respectively. The unfavorable change of $890 million was primarily driven by $1.06 billion less of a decrease in net
margin deposits (returns of cash deposits related to commodity contracts which support our hedging strategy) in the year ended
December 31, 2024 as compared to the year ended December 31, 2023. The unfavorable change in margin deposits is partially
offset by an increase in cash from realized operating income primarily due to the addition of Energy Harbor.
Depreciation and amortization — Depreciation and amortization expense, as reported as a reconciling adjustment in the
consolidated statements of cash flows, exceeded the amount reported in the consolidated statements of operations by $788
million, $454 million, and $451 million for the years ended December 31, 2024, 2023, and 2022, respectively. This difference
represents amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent
with industry practice, as well as the amortization of intangible net assets and liabilities. These are reported under various other
line items in the consolidated statements of operations, including operating revenues, fuel and purchased power costs, and
delivery fees (see Note 7 to the Financial Statements).
66

Investing Cash Flows
Cash used in investing activities totaled $5.276 billion and $2.145 billion for the years ended December 31, 2024 and
2023, respectively. The increase of $3.131 billion was driven primarily by the $3.1 billion used to fund the Energy Harbor
Merger.
Year Ended December 31,
Increase
(Decrease)
2024
2023
(in millions)
Capital expenditures, including LTSA prepayments
$
(801) $
(764)
(37)
Nuclear fuel purchases
(477)
(214)
(263)
Growth and development expenditures
(800)
(698)
(102)
Total capital expenditures
(2,078)
(1,676)
(402)
Energy Harbor acquisition (net of cash acquired)
(3,065)
—
(3,065)
Net sales (purchases) of environmental allowances
(453)
(571)
118
Net sales of (investments in) nuclear decommissioning trust fund securities
(23)
(23)
0
Proceeds from sales of property, plant, and equipment, including nuclear fuel
196
115
81
Proceeds from sales of transferable ITCs
150
—
150
Other investing activity
(3)
10
(13)
Cash used in investing activities
$
(5,276) $
(2,145) $
(3,131)
Financing Cash Flows
Cash used in financing activities totaled $1.604 billion and $294 million for the year ended December 31, 2024 and 2023,
respectively. The increase of $1.31 billion was primarily driven by the $1.748 billion paid to Avenue and Nuveen in connection
with the purchase of their noncontrolling interests in Vistra Vision and the $180 million of dividends we paid to them. These
cash outflows were partially offset by an $890 million increase in net new borrowings, as detailed below.
Year Ended December 31,
Increase
(Decrease)
2024
2023
(in millions)
Share repurchases
$
(1,266) $
(1,245) $
(21)
Issuances of long-term debt
3,817
2,498
1,319
Other net long-term borrowings (repayments)
(2,287)
(33)
(2,254)
Net short-term borrowings (repayments)
—
(650)
650
Net borrowings (repayments) under the accounts receivable financing facilities
750
(425)
1,175
Dividends paid to common stockholders
(305)
(313)
8
Dividends paid to preferred stockholders
(173)
(150)
(23)
Dividends paid to noncontrolling and redeemable noncontrolling interest holders
(180)
—
(180)
Payment for acquisition of noncontrolling interest
(1,748)
—
(1,748)
TRA Repurchase and tender offer — return of capital
(122)
—
(122)
Other financing activity
(90)
24
(114)
Cash used in financing activities
$
(1,604) $
(294) $
(1,310)
Debt Activity
We remain committed to a strong balance sheet and have continued to state our objective to reduce consolidated net
leverage. We also intend to maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend
maturities.
In May 2025, $744 million of 5.125% Senior Secured Notes will reach maturity. We plan to fund this upcoming principal
payment using a combination of proceeds from the senior secured notes issued in December 2024 and cash on hand. Increases
in interest rates have resulted in, and will likely continue to result in, increased borrowing costs.
67

See Note 9 to the Financial Statements for additional information.
Available Liquidity
The following table summarizes changes in available liquidity for the year ended December 31, 2024:
December 31, 2024
December 31, 2023
Change
(in millions)
Cash and cash equivalents (a)
$
1,188
$
3,485
$
(2,297)
Vistra Operations Credit Facilities — Revolving Credit Facility (b)
2,162
1,213
949
Vistra Operations — Commodity-Linked Facility (c)
771
1,101
(330)
Total available liquidity (d)(e)
$
4,121
$
5,799
$
(1,678)
____________
(a) See the consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the
decrease in cash and cash equivalents for the year ended December 31, 2024. The decrease includes $3.1 billion that was
used to fund the Energy Harbor Merger.
(b) The increase in availability for the year ended December 31, 2024 was driven by a $684 million decrease in letters of
credit outstanding under the facility and the October 2024 amendment to the Revolving Credit Facility which, among
other things, increased the revolving credit commitments by $265 million (see Note 9 to the Financial Statements).
(c) As of December 31, 2024 and 2023, the borrowing bases were less than the facility limits of $1.75 billion and $1.575
billion, respectively. As of December 31, 2024, available capacity reflects the borrowing base of $771 million and no cash
borrowings. As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash
borrowings.
(d) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See
Note 9 to the Financial Statements for additional information.
(e) Excludes any additional letters of credit that may be issued under the Secured LOC Facilities or the Alternative LOC
Facilities. See Note 9 to the Financial Statements for additional information.
We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the
next 12 months, including the upcoming payments associated with the acquisition of Nuveen's noncontrolling interest in Vistra
Vision discussed in Note 9 to the Financial Statements. Our operational cash flows tend to be seasonal and weighted toward the
second half of the year.
Interest payments on long-term debt, after taking into account interest rate swaps, are expected to total approximately
$905 million in 2025, $1.595 billion in 2026-2027, $1.180 billion in 2028-2029 and $1.305 billion thereafter. See Note 9 to the
Financial Statements for additional information.
Our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and
natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase
commitments, are expected to total approximately $3.270 billion in 2025, $2.650 billion in 2026-2027, $1.490 billion in
2028-2029 and $450 million thereafter. See Notes 10 and 15 to the Financial Statements for additional information.
Capital Expenditures
Estimated 2025 capital expenditures and nuclear fuel purchases as of December 31, 2024 total approximately $2.275
billion and include:
•
$925 million for investments in generation and mining facilities;
•
$725 million for solar and energy storage development;
•
$300 million for nuclear fuel purchases; and
•
$325 million for other growth expenditures.
68

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, Eligible Assets (see Note 8 to the Financial Statements) and other forms of credit support to satisfy such
collateral posting obligations. See Note 9 to the Financial Statements for additional information.
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.
As of December 31, 2024, we received or posted cash, letters of credit and Eligible Assets for commodity hedging and
trading activities as follows:
•
$841 million in cash and Eligible Assets has been posted with counterparties as compared to $1.244 billion posted as
of December 31, 2023;
•
$49 million in cash has been received from counterparties as compared to $45 million received as of December 31,
2023;
•
$2.560 billion in letters of credit have been posted with counterparties as compared to $2.408 billion posted as of
December 31, 2023; and
•
$131 million in letters of credit have been received from counterparties as compared to $143 million received as of
December 31, 2023.
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 expect to make approximately $31 million in federal income tax payments, $81 million in state
income tax payments and $2 million in TRA payments, offset by $14 million in state tax refunds.
For the year ended December 31, 2024, there were $5 million federal income tax payments, $59 million in state income
tax payments, $9 million in state income tax refunds and no TRA payments.
Capitalization
Our capitalization ratios consisted of 73% and 70% long-term debt (less amounts due currently) and 27% and 30%
stockholders' equity at December 31, 2024 and 2023, respectively. Total long-term debt (including amounts due currently) to
capitalization was 75% and 73% at December 31, 2024 and 2023, respectively.
69

Financial Covenants
The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a
covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a
compliance period (which, in general, is applicable when the aggregate revolving borrowings and revolving letters of credit
outstanding (excluding all undrawn revolving letters of credit and cash collateralized backstopped revolving letters of credit)
exceed 35% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00
(or, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). In addition, each
of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25
to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the
consolidated total net leverage ratio not to exceed 5.50 to 1.00). Although the period ended December 31, 2024 was not a
compliance period, we would have been in compliance with the Vistra Operations Credit Agreement, Vistra Operations
Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants if they were required to be tested at such
time. See Note 9 to the Financial Statements for additional information.
Collateral Support Obligations
The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the
RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is
effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities)
that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation
of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits
have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory
obligations by the RCT, and includes cost contingency amounts.
The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer
deposits, if necessary. Under these rules, as of December 31, 2024, Vistra has posted letters of credit in the amount of $86
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 $960 million in the form
of letters of credit, $70 million in the form of a surety bond and $3 million of cash as of December 31, 2024 (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 the greatest of $1.0 billion, 17.5% of Consolidated EBITDA and 2.50% of Consolidated Total
Assets, may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility. Such a
default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities,
which totaled approximately $2.475 billion and zero, respectively, as of December 31, 2024.
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.
70

Under the Vistra Operations Senior Unsecured Indentures, the Vistra Operations Senior Secured Indenture and the
Indenture governing the 7.233% Senior Secured Notes, 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 7.233% 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, Energy Harbor LLC, TriEagle Energy, each
indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), and Vistra or any of their respective
subsidiaries fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at
least $300 million, in the case of Vistra Operations, and in a principal amount of at least $50 million, in the case of TXU
Energy or any of the other Originators, 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 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 Secured LOC
Facilities. In addition, 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.
Under the Alternative LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of
certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated
EBITDA may result in a cross default under the Alternative LOC Facilities. In addition, 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 exceeding the
threshold above, may result in a termination of the Alternative LOC Facilities.
Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing
the 7.750% Senior Unsecured Notes, the 6.875% Senior Unsecured Notes, the 6.950% Senior Secured Notes and the 6.000%
Senior Secured Notes, 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 that exceeds the greater of 1.5% of total assets and $600 million may result in a cross
default under the respective notes 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.
A default by Vistra Zero Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an
aggregate amount in excess of the greatest of $100 million, 75% of Consolidated EBITDA and 6% of Consolidated Total
Assets, may result in a cross default under the Vistra Zero Credit Agreement. Such a default would allow the lenders under such
facility to accelerate the maturity of outstanding balances under such facility, which totaled approximately $697 million as of
December 31, 2024.
71

A default by BCOP or any of its subsidiary guarantors in respect of certain provisions defined in the applicable agreement
may result in a cross default under the BCOP Credit Agreement. Such a default would allow the lenders under such facility to
accelerate the maturity of outstanding balances under such facility. In addition, the interest rate swap agreements that are
secured with a lien on BCOP and its subsidiary guarantors' assets on a pari passu basis with the BCOP Credit Agreement
contain cross-default provisions, where an event of a default by BCOP or any of its subsidiary guarantors 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 BCOP and require all outstanding obligations under such agreement to be settled.
Under the Nuveen UPA, a default under any document evidencing indebtedness for borrowed money by Vistra Operations
or any Guarantor Subsidiary that results in the acceleration of such indebtedness in an aggregate amount that exceeds the
greater of 1.5% of total assets and $600 million may result in a cross default under the UPA. Such a default would result in the
payment obligations under the Nuveen UPA of Vistra Vision Holdings and/or any guarantor thereunder becoming immediately
due and payable.
Guarantees
See Note 15 to the Financial Statements for additional information.
Commitments and Contingencies
See Note 15 to the Financial Statements for additional information.
Changes in Accounting Standards
See Note 1 to the Financial Statements for additional information.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In the normal course of business, our financial position is routinely subject to a variety of risks, including market risks
associated with (i) changes in commodity prices, (ii) interest rate movements on outstanding debt, and (iii) credit risk, which is
the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due to us.
Market risks are monitored by our risk management group which operates independently of the wholesale commercial
operations, utilizing defined practices and analytical methodologies. These practices and methodologies measure the risk of
change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions.
Measurement techniques include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and
stress test scenarios. Risk management regularly reports their analysis to the Company's Risk Committee and Executive
Committee, and to the Sustainability and Risk Committee of the Board of Directors.
Commodity Price Risk and Oversight
Our business is subject to the inherent risks of market fluctuations in the price of commodities for energy-related products
we market or purchase in futures markets including electricity, natural gas, uranium, coal, environmental credits and other
energy commodities in competitive wholesale markets. Factors that influence these market fluctuations are dependent upon
many factors outside of our control including seasonal changes in supply and demand, weather conditions, market liquidity,
governmental, regulatory, and environmental policies.
We manage the commodity price and commodity-related operational risk related to the competitive energy business
within limitations established by senior management and in accordance with overall risk management policies. In managing
commodity price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts
for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Similar
to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in
natural gas and power prices. Beginning in 2024, our nuclear fleet is eligible for the nuclear PTC provided by the IRA which
provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted
annually for inflation over the duration of the program.
72

VaR Methodology
A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of
market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level
and considers, among other things, market movements utilizing standard statistical techniques given historical and projected
market prices and volatilities.
Parametric processes are used to calculate VaR and are considered by management to be the most effective way to
estimate changes in a portfolio's value based on assumed market conditions for liquid markets. This measurement estimates the
potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts. The use of this
method requires a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period
(i.e., the time necessary for management action, such as to liquidate positions), and (iii) historical estimates of volatility and
correlation data.
The following table summarizes the VaR for Vistra's commodity portfolio based on a 95% confidence level and an
assumed holding period of 60 days. Average VaRs as of December 31 are the average of each month-end average for the years
ended December 31, 2024 and 2023, respectively:
Year Ended December 31,
2024
2023
Average VaR
$
236
$
190
High VaR
$
371
$
423
Low VaR
$
86
$
115
The month-end average VaR risk measure increased in 2024 due to higher volumes following the Energy Harbor Merger.
Interest Rate Risk
We are exposed to fluctuations in interest rates through our issuance of variable rate debt. We mitigate our exposure to
fluctuations in interest rates through entering interest rate swaps. These interest rate swaps limit the impact of interest rate
changes on our results of operations and cash flows and to lower our overall borrowing costs. Interest rate risk is managed
centrally by our treasury function.
As of December 31, 2024, we have approximately $3.5 billion principal amount of variable rate debt consisting of the
Vistra Operations Credit Facilities Term Loan B-3 Facility, the BCOP Credit Facilities and the Vistra Zero Term Loan B
Facility (see Note 9 to the Financial Statements). We have entered into net notional interest rate swaps that will hedge $2.3
billion of our exposure to variable rate debt through December 2030 (see Note 11 to Financial Statements). As of December 31,
2024, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis
points) increase in floating interest rates on long-term debt totaled approximately $12 million after taking into account the
interest rate swaps.
Credit Risk
Our primary concentration of credit risk is associated with the collection of receivables resulting from sales to retail
customers and the risk of a counterparty's failure to meet its obligations under derivative contracts. We minimize our exposure
to credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk.
This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other
quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized
master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and
customer deposits, letters of credit, parental guarantees and surety bonds. See Note 11 to the Financial Statements for additional
information.
73

Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable
and net derivative assets arising from commodity contracts and hedging and trading activities totaled $2.360 billion at
December 31, 2024. Including collateral posted to us by counterparties, our net exposure was $2.166 billion, as seen in the
following table that presents the distribution of credit exposure by counterparty credit quality as of December 31, 2024. Credit
collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.
Exposure Before Credit Collateral
Trade Accounts
Receivable
Derivatives
Gross
Exposure
Credit
Collateral
Net
Exposure
(in millions)
Retail segment
$
1,545
$
—
$
1,545
$
51
$
1,494
Texas, East and Asset Closure segments:
Investment grade
$
99
$
451
$
550
$
49
$
501
Below investment grade or no rating
69
196
265
94
171
Texas, East and Asset Closure segments
$
168
$
647
$
815
$
143
$
672
Totals
$
1,713
$
647
$
2,360
$
194
$
2,166
Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market
in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is
favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.
An event of default by one or more counterparties could subsequently result in termination-related settlement payments
that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of
expected settlements owed to us. Significant (i.e., 10% or greater) concentration of credit exposure exists with one counterparty,
which represented an aggregate $262 million, or 39%, of our total net exposure as of December 31, 2024. We view exposure to
this counterparty to be within an acceptable level of risk tolerance due to the counterparty's credit ratings, the counterparty's
market role and deemed creditworthiness and the importance of our business relationship with the counterparty.
74

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Vistra Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Vistra Corp. and subsidiaries (the “Company”) as of
December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income (loss), cash flows, and
changes in equity, for each of the three years in the period ended December 31, 2024, and the related notes and the schedule
listed in the Index at Item 15(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements
present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results
of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with
accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in
Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 27, 2025, expressed an unqualified opinion on the Company’s internal control over
financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that
were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and
we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on
the accounts or disclosures to which they relate.
Fair Value Measurements — Certain Complex Level 3 Derivative Assets and Liabilities — Refer to Notes 1 and 12 to
the financial statements
Critical Audit Matter Description
The Company has derivative assets and liabilities whose fair values are based on complex proprietary models and/or
unobservable inputs. These financial instruments can span a broad array of contract types, some of which include especially
complex valuations due to unique contract terms and significant judgement by management in estimating prices or volumes,
including (1) power purchases and sales that include power and heat rate positions; (2) physical power and natural gas options
and swaptions; (3) forward purchase contracts for congestion revenue rights; and (4) retail sales contracts. Under accounting
principles generally accepted in the United States of America, these financial instruments are generally classified as Level 3
derivative assets or liabilities.
75

Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of the
aforementioned Level 3 derivative assets and liabilities, performing audit procedures to evaluate the reasonableness of the fair
value of Level 3 derivative assets and liabilities required a high degree of auditor judgment and an increased extent of effort,
including the need to involve our energy commodity fair value specialists who possess significant quantitative and modeling
expertise.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the following,
among others:
•
We tested the effectiveness of internal control over derivative asset and liability valuations, including internal control
related to appropriate application of illiquid price curves and other significant unobservable valuation inputs.
•
We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December
31, 2024, to obtain an understanding of the types of instruments outstanding.
•
We assessed the consistency by which management has applied illiquid price curves and significant unobservable
valuation inputs.
•
With the assistance of our energy commodity fair value specialists, we developed independent estimates of the fair
value of a sample of Level 3 derivative instruments and compared our estimates to the Company's estimates.
Energy Harbor Holdings LLC Acquisition — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company completed the acquisition of Energy Harbor Holdings LLC (formerly known as Energy Harbor Corp., “Energy
Harbor”) for cash consideration of $3.1 billion and granting a 15% minority interest in certain Vistra businesses with a fair
value estimated at $1.5 billion (collectively, the “purchase price consideration”) on March 1, 2024. The Company accounted for
the acquisition of Energy Harbor as a business combination. Accordingly, the excess of the purchase price consideration over
the identifiable assets acquired and liabilities assumed, was recorded as goodwill.
In connection with the business combination, the Company recorded $5.6 billion in property, plant and equipment, which
includes the value of the three nuclear power plants. Additionally, a portion of the purchase price consideration also included
the fair value of a 15% minority interest in Vistra’s nuclear power plant.
The nuclear power plants were valued using a
combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis
based upon a debt-free cash flow model. The determination of the discounted cash flow model fair value of the nuclear plants
included significant judgment and assumptions by management, including future commodity prices, earned production tax
credits, anticipated production volumes, future operating costs and capital expenditures, and the discount rate applied to the
nuclear plant cash flows.
Given the valuation of the nuclear power plants involved complex and subjective estimates of forecasted future growth and
financial performance, performing audit procedures to evaluate the reasonableness of the valuation required a high degree of
auditor judgment and an increased extent of effort, including the need to involve our fair value specialists who possess
specialized skills and knowledge in modeling the fair value of long term assets.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the evaluation of the fair value of the nuclear power plants included the following, among
others:
•
We tested the effectiveness of internal control over the nuclear power plant valuations, including internal control
related to the appropriateness of significant assumptions that are inputs to the fair value calculation and management's
review of the valuation model.
•
We obtained and read the third-party valuation report and evaluated the competency of the third-party specialist
engaged by management to perform the valuations.
•
With the assistance of our fair value specialists, we evaluated the appropriateness of management’s methodology,
significant assumptions used to develop the fair value estimate, including the reasonableness of the discount cash
flow model itself, the discount rate, present value factor, terminal value, and the internal rate of return, and tested the
mathematical accuracy of the calculation.
76

•
We evaluated the completeness and accuracy of the underlying data used to develop the forecasts of future cash
flows, including assessing the reasonableness of the key assumptions.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 27, 2025
We have served as the Company’s auditor since 2002.
77

VISTRA CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions of Dollars, Except Share Data)
Year Ended December 31,
2024
2023
2022
Operating revenues
$
17,224
$
14,779
$
13,728
Fuel, purchased power costs, and delivery fees
(7,285)
(7,557)
(10,401)
Operating costs
(2,414)
(1,702)
(1,645)
Depreciation and amortization
(1,843)
(1,502)
(1,596)
Selling, general, and administrative expenses
(1,601)
(1,308)
(1,189)
Impairment of long-lived and other assets
—
(49)
(74)
Operating income (loss)
4,081
2,661
(1,177)
Other income
312
257
117
Other deductions
(21)
(14)
(4)
Interest expense and related charges
(900)
(740)
(368)
Impacts of Tax Receivable Agreement
(5)
(164)
(128)
Net income (loss) before income taxes
3,467
2,000
(1,560)
Income tax (expense) benefit
(655)
(508)
350
Net income (loss)
2,812
1,492
(1,210)
Net (income) loss attributable to noncontrolling interest and redeemable
noncontrolling interest
(153)
1
(17)
Net income (loss) attributable to Vistra
2,659
1,493
(1,227)
Cumulative dividends attributable to preferred stock
(192)
(150)
(150)
Net income (loss) attributable to Vistra common stock
$
2,467
$
1,343
$
(1,377)
Weighted average shares of common stock outstanding:
Basic
344,788,634
369,771,359
422,447,074
Diluted
352,567,060
375,193,110
422,447,074
Net income (loss) per weighted average share of common stock
outstanding:
Basic
$
7.16
$
3.63
$
(3.26)
Diluted
$
7.00
$
3.58
$
(3.26)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
Year Ended December 31,
2024
2023
2022
Net income (loss)
$
2,812
$
1,492
$
(1,210)
Other comprehensive income (loss), net of tax effects:
Effects related to pension and other retirement benefit obligations (net of
tax expense of $4, $— and $7)
14
(1)
23
Total other comprehensive income (loss)
14
(1)
23
Comprehensive income (loss)
2,826
1,491
(1,187)
Comprehensive (income) loss attributable to noncontrolling interest and
redeemable noncontrolling interest
(153)
1
(17)
Comprehensive income (loss) attributable to Vistra
$
2,673
$
1,492
$
(1,204)
See Notes to the Consolidated Financial Statements
78

ASSETS
Current assets:
Cash and cash equivalents
$
1,188
$
3,485
Restricted cash
28
40
Trade accounts receivable — net
1,982
1,674
Income taxes receivable
8
6
Inventories
970
740
Commodity and other derivative contractual assets
2,587
3,645
Margin deposits related to commodity contracts
406
1,244
Margin deposits posted under affiliate financing agreement
435
439
Prepaid expense and other current assets
515
364
Total current assets
8,119
11,637
Restricted cash
6
14
Investments
4,512
2,035
Property, plant, and equipment — net
18,173
12,432
Goodwill
2,807
2,583
Identifiable intangible assets — net
2,213
1,864
Commodity and other derivative contractual assets
740
577
Accumulated deferred income taxes
9
1,223
Other noncurrent assets
1,191
601
Total assets
$
37,770
$
32,966
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable financing
$
750
$
—
Long-term debt due currently
880
2,286
Forward repurchase obligation due currently
703
—
Trade accounts payable
1,510
1,147
Commodity and other derivative contractual liabilities
3,351
5,258
Margin deposits related to commodity contracts
49
45
Accrued taxes other than income
209
203
Accrued interest
193
206
Asset retirement obligations
142
124
Other current liabilities
645
554
Total current liabilities
8,432
9,823
Margin deposits financing with affiliate
435
439
Long-term debt, less amounts due currently
15,418
12,116
Forward repurchase obligation, less amounts due currently
632
—
Commodity and other derivative contractual liabilities
1,367
1,688
Accumulated deferred income taxes
697
1
Tax Receivable Agreement obligation
14
164
Asset retirement obligations
3,936
2,414
Other noncurrent liabilities and deferred credits
1,256
999
Total liabilities
32,187
27,644
Commitments and Contingencies
VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Share Data)
December 31,
2024
2023
See Notes to the Consolidated Financial Statements
79

Total equity:
Preferred stock (100,000,000 shares authorized, $1,000 liquidation preference per share,
2,476,066 and 2,476,081 shares outstanding at December 31, 2024 and 2023,
respectively)
2,476
2,476
Common stock (par value $0.01 per share, 1,800,000,000 shares authorized, 339,754,307
and 351,457,016 shares outstanding at December 31, 2024 and 2023, respectively)
5
5
Treasury stock, at cost (208,998,299 and 192,178,156 shares at December 31, 2024 and
2023, respectively)
(5,912)
(4,662)
Additional paid-in-capital
9,435
10,095
Accumulated deficit
(454)
(2,613)
Accumulated other comprehensive income
20
6
Stockholders' equity
5,570
5,307
Noncontrolling interest in subsidiary
13
15
Total equity
5,583
5,322
Total liabilities and equity
$
37,770
$
32,966
VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Share Data)
December 31,
2024
2023
See Notes to the Consolidated Financial Statements
80

Cash flows — operating activities:
Net income (loss)
$
2,812
$
1,492
$
(1,210)
Adjustments to reconcile net income (loss) to cash provided by (used in)
operating activities:
Depreciation and amortization
2,631
1,956
2,047
Deferred income tax expense (benefit), net
607
457
(359)
Gain on sale of land
—
(95)
(8)
Impairment of long-lived and other assets
—
49
74
Unrealized net (gain) loss from mark-to-market valuations of
commodities
(1,155)
(490)
2,510
Unrealized net (gain) loss from mark-to-market valuations of interest
rate swaps
(53)
36
(250)
Unrealized net gain from nuclear decommissioning trusts
(116)
—
—
Change in asset retirement obligation liability
38
27
13
Asset retirement obligation accretion expense
114
34
34
Impacts of Tax Receivable Agreement
5
164
128
Gain on TRA repurchase and tender offers
(10)
(29)
—
Bad debt expense
183
164
179
Stock-based compensation
100
77
63
Other, net
(89)
103
(71)
Changes in operating assets and liabilities:
Accounts receivable — trade
(242)
214
(852)
Inventories
(31)
(174)
36
Accounts payable — trade
19
(350)
94
Commodity and other derivative contractual assets and liabilities
(175)
82
(228)
Margin deposits, net
842
1,899
(1,874)
Uplift securitization proceeds receivable from ERCOT
—
—
544
Accrued interest
(18)
46
16
Accrued taxes
(1)
5
(8)
Accrued employee incentive
8
58
21
Asset retirement obligation settlement
(88)
(81)
(87)
Major plant outage deferral
(91)
(32)
20
Other — net assets
(616)
84
(17)
Other — net liabilities
(111)
(243)
(330)
Cash provided by operating activities
4,563
5,453
485
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA
prepayments
(2,078)
(1,676)
(1,301)
Energy Harbor acquisition (net of cash acquired)
(3,065)
—
—
Proceeds from sales of nuclear decommissioning trust fund securities
2,216
601
670
Investments in nuclear decommissioning trust fund securities
(2,239)
(624)
(693)
Proceeds from sales of environmental allowances
773
500
1,275
Purchases of environmental allowances
(1,226)
(1,071)
(1,303)
Proceeds from sales of property, plant, and equipment, including nuclear
fuel
196
115
78
Proceeds from sales of transferable ITCs
150
—
—
VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
2024
2023
2022
See Notes to the Consolidated Financial Statements
81

Other, net
(3)
10
35
Cash used in investing activities
(5,276)
(2,145)
(1,239)
Cash flows — financing activities:
Issuances of long-term debt
3,817
2,498
1,498
Repayments/repurchases of debt
(2,287)
(33)
(251)
Net borrowings (repayments) under accounts receivable financing
750
(425)
425
Borrowings under Revolving Credit Facility
50
100
1,750
Repayments under Revolving Credit Facility
(50)
(350)
(1,500)
Borrowings under Commodity-Linked Facility
1,802
—
3,150
Repayments under Commodity-Linked Facility
(1,802)
(400)
(2,750)
Debt issuance costs
(76)
(59)
(31)
Stock repurchases
(1,266)
(1,245)
(1,949)
Dividends paid to common stockholders
(305)
(313)
(302)
Dividends paid to preferred stockholders
(173)
(150)
(151)
Dividends paid to noncontrolling and redeemable noncontrolling interest
holders
(180)
—
—
Payment for acquisition of noncontrolling interest
(1,748)
—
—
TRA Repurchase and tender offer — return of capital
(122)
—
—
Other, net
(14)
83
31
Cash used in financing activities
(1,604)
(294)
(80)
Net change in cash, cash equivalents and restricted cash
(2,317)
3,014
(834)
Cash, cash equivalents and restricted cash — beginning balance
3,539
525
1,359
Cash, cash equivalents and restricted cash — ending balance
$
1,222
$
3,539
$
525
VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
2024
2023
2022
See Notes to the Consolidated Financial Statements
82

Balances at
December 31, 2021
$ 2,000
$
5
$(1,558) $ 9,824
$ (1,964) $
(16) $
8,291
$
1
$ 8,292
Stock repurchases
—
—
(1,837)
—
—
—
(1,837)
—
(1,837)
Effects of stock-based
incentive
compensation plans
—
—
—
103
—
—
103
—
103
Net income (loss)
—
—
—
—
(1,227)
—
(1,227)
17
(1,210)
Dividends declared on
common stock
—
—
—
—
(302)
—
(302)
—
(302)
Dividends declared on
preferred stock
—
—
—
—
(151)
—
(151)
—
(151)
Change in
accumulated other
comprehensive income
(loss)
—
—
—
—
—
23
23
—
23
Other
—
—
—
1
1
—
2
(2)
—
Balances at
December 31, 2022
$ 2,000
$
5
$(3,395) $ 9,928
$ (3,643) $
7
$
4,902
$
16
$ 4,918
Series C Preferred
Stock issued
476
—
—
—
—
—
476
—
476
Stock repurchases
—
—
(1,267)
—
—
—
(1,267)
—
(1,267)
Effects of stock-based
incentive
compensation plans
—
—
—
168
—
—
168
—
168
Net income (loss)
—
—
—
—
1,493
—
1,493
(1)
1,492
Dividends declared on
common stock
—
—
—
—
(313)
—
(313)
—
(313)
Dividends declared on
preferred stock
—
—
—
—
(150)
—
(150)
—
(150)
Change in
accumulated other
comprehensive income
(loss)
—
—
—
—
—
(1)
(1)
—
(1)
Other
—
—
—
(1)
—
—
(1)
—
(1)
Balances at
December 31, 2023
$ 2,476
$
5
$(4,662) $10,095
$ (2,613) $
6
$
5,307
$
15
$ 5,322
Stock repurchases
(1,250)
(1,250)
(1,250)
Effects of stock-based
incentive
compensation plans
—
—
—
140
—
—
140
—
140
Net income
—
—
—
—
2,659
—
2,659
102
2,761
Dividends declared on
common stock
—
—
—
—
(307)
—
(307)
—
(307)
Dividends declared on
preferred stock
—
—
—
—
(192)
—
(192)
—
(192)
Dividends to
noncontrolling interest
—
—
—
—
—
—
—
(15)
(15)
Change in
accumulated other
comprehensive income
(loss)
—
—
—
—
—
14
14
—
14
Equity issued in
subsidiary to acquire
Energy Harbor
—
—
—
747
—
—
747
1,560
2,307
VISTRA CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)
Preferred
Stock
Common
Stock
Treasury
Stock
Additional
Paid-In
Capital
Accumulated
Deficit
Accumulated
Other
Comprehensive
Income (Loss)
Total
Stockholders'
Equity
Noncontrolling
Interest in
Subsidiary
Total
Equity
See Notes to the Consolidated Financial Statements
83

Modification of
noncontrolling interest
to redeemable
noncontrolling interest
(a)
—
—
—
(1,539)
—
—
(1,539)
(1,659)
(3,198)
Other
—
—
—
(8)
(1)
—
(9)
10
1
Balances at
December 31, 2024
$ 2,476
$
5
$(5,912) $ 9,435
$
(454) $
20
$
5,570
$
13
$ 5,583
VISTRA CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)
Preferred
Stock
Common
Stock
Treasury
Stock
Additional
Paid-In
Capital
Accumulated
Deficit
Accumulated
Other
Comprehensive
Income (Loss)
Total
Stockholders'
Equity
Noncontrolling
Interest in
Subsidiary
Total
Equity
____________
(a)
See Note 2 for additional information regarding activity associated with noncontrolling interest.
See Notes to the Consolidated Financial Statements
84

VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business
References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the
context. See Glossary of Terms and Abbreviations for defined terms.
Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets
throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity
generation, wholesale energy sales and purchases, commodity risk management, and retail sales of electricity and natural gas to
end users.
Vistra has five reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. See Note 19 for
additional information.
Significant Accounting Policies
Basis of Presentation
The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the
audited financial statements included in our 2023 Form 10-K. All intercompany items and transactions have been eliminated in
consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless
otherwise indicated. Certain prior period amounts have been reclassified to conform with the current year presentation.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of
assets and liabilities as of the balance sheet dates and the reported amounts of revenue and expense, including fair value
measurements, estimates of expected obligations, judgments related to the potential timing of events, and other estimates. In the
event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to
reflect more current information.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, which
requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed,
and any noncontrolling interest in the acquiree at fair value as of the acquisition date. The excess of the purchase price over
those fair values is recognized as goodwill (if any). During the measurement period, which may be up to one year from the
acquisition date, we may record adjustments to the assets acquired and liabilities assumed in the period in which they are
determined. See Note 2 for additional information.
Derivative Instruments and Mark-to-Market Accounting
We enter derivative instruments, including commodity contracts and interest rate swaps, to manage commodity price and
interest rate risks. All our derivatives are accounted for as economic hedges and are recorded at estimated fair value in the
consolidated balance sheets with changes in fair value recorded as gains or losses in the earnings of the period in which they
occur. No derivative positions are accounted for as cash flow or fair value hedges. When derivative instruments are settled and
realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities
are reversed.
A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be
physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract
is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement
recognition of the contract until settlement.
85

We report derivative instruments in the consolidated balance sheets as commodity and other derivative contractual assets
or liabilities on a gross basis without taking into consideration netting arrangements we have with counterparties. We maintain
standardized master netting agreements with certain counterparties that allow for the right to offset derivative assets and
liabilities, receivables and payables on settled positions, and collateral to reduce credit exposure between us and the
counterparty.
Generally, margin deposits that contractually offset derivative instruments are reported separately in the consolidated
balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally
characterized as settlement of forward exposure rather than collateral.
We report commodity hedging and trading results as revenue, fuel expense, or purchased power in the consolidated
statements of operations depending on the type of activity. Electricity hedges, financial natural gas hedges, and trading
activities are primarily reported as revenue. Physical hedges for coal or fuel oil, along with physical natural gas trades, are
primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swap transactions are
reported in the consolidated statements of operations in interest expense. See Note 11 for additional information.
Revenue Recognition
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes
delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not
billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the
last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are
adjusted when actual usage is known and billed.
We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are
not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO,
ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response
available for system reliability requirements, and certain other electricity sales contracts. See Note 3 for additional information.
See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts.
Government Assistance
The Company qualifies for tax incentives through eligible construction spending and production through the Inflation
Reduction Act of 2022 (IRA). These tax incentives generally provide for transferable tax credits upon the applicable qualifying
event for the credit type, typically production or in-service date. We account for transferable ITCs and PTCs we expect to
receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and
Disclosures of Government Assistance (IAS 20). Transferable PTCs are included in other noncurrent assets in the consolidated
balance sheet and included in revenues in the consolidated statements of operations when receipt of the credit is reasonably
assured. Transferable investment tax credits (ITCs) are included in other noncurrent assets on the consolidated balance sheet
with a corresponding reduction to the cost basis of the Company's plant assets when receipt of the credit is reasonably assured,
and reduces depreciation expense over the life of the asset. We believe the reasonable assurance term as used in IAS 20 is
analogous to the term probable as defined in ASC 450-20 of U.S. GAAP. See Note 4 for additional information.
Major Maintenance Costs
Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over
the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are
charged to expense as incurred and reported as operating costs in the consolidated statements of operations.
Defined Benefit Pension Plans and OPEB Plans
Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement
of such employees from the company. Pension benefits are offered to eligible employees under collective bargaining
agreements based on either a traditional defined benefit formula or a cash balance formula. Costs of pension and OPEB plans
are dependent upon numerous factors, assumptions and estimates. See Note 14 for additional information.
86

Stock-Based Compensation
Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. We
recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the
entire award. Forfeitures are recognized as they occur. See Note 18 for additional information.
Sales and Excise Taxes
Sales and excise taxes are accounted for as "pass through" items in the consolidated balance sheets with no effect on the
consolidated statements of operations (i.e., the tax is billed to customers and recorded as trade accounts receivable with an
offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in the consolidated statements of
operations).
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed
on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as
an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt
taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in
SG&A expense in the consolidated statements of operations.
Income Taxes
Deferred income tax assets and liabilities are recorded to reflect, among other things, the temporary timing differences
between the book basis and tax basis of assets and liabilities, as required under accounting rules. Investment tax credits that are
not transferable are accounted for using the deferral method, which reduces the tax basis of our solar and battery storage
facilities. As of both December 31, 2024 and 2023, deferred tax assets related to these credits totaled $69 million. We report
interest and penalties related to uncertain tax positions as current income tax expense. See Note 5 for additional information.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss
contingencies are recorded when management determines that it is probable that a liability has been incurred and that such
economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and
circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 15 for additional
information.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with an original maturity of
three months or less are considered cash equivalents.
Property, Plant, and Equipment
Property, plant, and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or
at cost for capital improvements and individual facilities developed. Significant improvements or additions to our property,
plant, and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when
incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-
related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance
with accounting guidance related to capitalization of interest cost.
Depreciation of our property, plant, and equipment (except for nuclear fuel) is calculated on a straight-line basis over the
estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable
lives are based on management's estimates of the assets' economic useful lives. See Note 6 for additional information.
87

Nuclear Fuel
Nuclear fuel is capitalized and reported as a component of our property, plant, and equipment in the consolidated balance
sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel,
purchased power costs, and delivery fees in the consolidated statements of operations.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of
impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less
than the carrying value. If there is such impairment, a loss is recognized based on the amount by which the carrying value
exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if
applicable. See Note 6 for additional information.
Goodwill and Intangible Assets with Indefinite Lives
As part of our fresh start reporting and purchase accounting from acquisitions, reorganization value or the purchase
consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and
liabilities, then any remaining excess reorganization value or purchase consideration is allocated to goodwill. We evaluate
goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist.
We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. See
Note 7 for additional information.
Asset Retirement Obligations (ARO)
A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation
associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in
which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also
recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful
life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to
lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for the change
in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes
in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information
becomes available. Changes in estimates related to assets that have been retired or for which costs are not recoverable are
recorded as operating costs in the consolidated statements of operations. See Note 13 for additional information.
Inventories
Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is
valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects,
respectively. Fuel stock and natural gas in storage are reported at the lower of cost (calculated on a weighted average basis) or
net realizable value. We expect to recover the value of inventory costs in the normal course of business. See Note 20 for
additional information.
Nuclear Decommissioning Trust (NDT) Investments and Regulatory Assets or Liability
The NRC is responsible for regulating all nuclear power plants in the U.S. This regulatory oversight results in specific
accounting considerations for nuclear plant decommissioning. Our NDTs hold funds primarily for the ultimate
decommissioning of our nuclear power plants. Each unit has its own NDT and funds from one unit may not be used to fund
decommissioning obligations of another unit.
Decommissioning costs associated with the Comanche Peak nuclear generation facility in Texas are being recovered from
Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited
by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the NDT. As a result, the asset retirement obligation and
the investments in the decommissioning trust are accounted for as rate regulated operations. Changes in these accounts,
including investment income and accretion expense, do not impact net income, but are reported as a change in the
corresponding regulatory asset or liability balance that is reflected in the consolidated balance sheets as other noncurrent assets
or other noncurrent liabilities and deferred credits.
88

The NDTs associated with our PJM nuclear facilities have been funded with amounts collected from the previous owners
and their respective utility customers. Any shortfall of funds necessary for decommissioning the PJM nuclear facilities,
determined for each generating station unit, are required to be funded by us. Investments in the PJM NDTs are carried at fair
value and gains and losses are recognized as other income or other deductions in the consolidated statements of operations.
NDTs are invested in diversified portfolios of securities generally designed to achieve a return sufficient to fund the future
decommissioning work. We retain any funds remaining in the trusts of the PJM nuclear facilities after all decommissioning has
been completed.
Noncontrolling Interest and Redeemable Noncontrolling Interest in Subsidiary
A noncontrolling interest in a consolidated subsidiary represents the portion of the equity in a subsidiary not attributable,
directly or indirectly, to the Company. Noncontrolling interests are presented as a separate component of equity in the
consolidated balance sheets and the presentation of net income is modified to present earnings attributed to controlling and
noncontrolling interests. Any change in ownership of a subsidiary while the controlling financial interest is retained is
accounted for as an equity transaction between the controlling and noncontrolling interests. See Note 2 for additional
information.
Redeemable noncontrolling interests are presented as a component of temporary equity in the mezzanine section of the
consolidated balance sheet and the presentation of net income is modified to present earnings attributed to the controlling and
redeemable noncontrolling interest. In December 2024, we closed on the repurchase of the noncontrolling interest in Vistra
Vision and reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing
obligation. See Note 2 and Note 9 for additional information.
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is
recorded as treasury stock, which is presented in the consolidated balance sheets as a reduction to additional paid-in capital.
Treasury stock purchases made by third party brokers on our behalf are recorded on a trade date basis when we are
contractually obligated to pay the broker for their repurchase costs. See Note 16 for additional information.
Leases
At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to
control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for
consideration.
Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent
our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the
commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our
secured incremental borrowing rate based on the information available at the lease commencement date to determine the present
value of lease payments. Operating leases are included in other noncurrent assets, other current liabilities, and other noncurrrent
liabilities and deferred credits on the consolidated balance sheet. Finance leases are included in property, plant, and equipment,
other current liabilities and other noncurrent liabilities and deferred credits on the consolidated balance sheet. Lease term
includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the
practical expedient permitted by ASC 842, Leases to not separate lease and non-lease components for a majority of our lease
asset classes.
Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense
for these leases on a straight-line basis over the lease term.
89

Adoption of Accounting Standards in 2024
Improvements to Reportable Segment Disclosures
In November 2023, the Financial Accounting Standards Board (FASB) issued ASU No. 2023-07, Segment Reporting
(Topic 280), Improvements to Reportable Segment Disclosures, to improve the disclosures about reportable segments and add
more detailed information about a reportable segment's expenses. The amendments in the ASU require public entities to
disclose on an annual and interim basis significant segment expenses that are regularly provided to the chief operating decision
maker (CODM) and included within each reported measure of segment profit or loss, other segment items by reportable
segment, the title and position of the CODM, and an explanation of how the CODM uses the reported measures of segment
profit or loss in assessing segment performance and deciding how to allocate resources. The ASU does not change the
definition of a segment, the method for determining segments, the criteria for aggregating operating segments into reportable
segments, or the current specifically enumerated segment expenses that are required to be disclosed. The Company adopted the
amendments in this ASU for its fiscal year ended December 31, 2024 which resulted in disclosure of significant segment
expenses such as segment fuel, purchased power costs, and delivery fees, operating costs, and selling, general, and
administrative expenses. The amendment was applied retrospectively to all prior periods presented. See Note 19 for additional
information.
Recent Accounting Pronouncements
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU No. 2023-09 (ASU 2023-09), Income Taxes (Topic 740): Improvements to
Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is
effective for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. As the
amendments apply to income tax disclosures only, the Company does not expect adoption to have a material impact on the
consolidated financial statements.
Expense Disaggregation Disclosures
In November 2024, the FASB issued ASU No. 2024-03 (ASU 2024-03), Income Statement – Reporting Comprehensive
Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve
disclosures by providing additional information about certain expenses in the notes to financial statements in interim and annual
reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as
employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face
of the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods
within annual reporting periods beginning after December 15, 2027 and can be applied prospectively or retrospectively. Early
adoption is permitted. We are currently evaluating the impact this ASU will have on the consolidated financial statements and
related disclosures.
Recent Developments
In January, a fire occurred at our Moss Landing 300 MW battery energy storage facility in the West segment. We are still
investigating the cause of the fire and impacts, including insurance claim recoveries, but expect to write off approximately
$400 million of plant value to depreciation expense in the first quarter of 2025, representing the remaining net book value of the
facility. Moss Landing 300 is part of the Moss Landing complex, which includes two other battery facilities and a gas plant,
with an aggregate book value of approximately $1 billion. While the gas plant is operational, the other two battery facilities
remain offline as we investigate the fire. We will continue to assess if a triggering event has occurred to evaluate impairment
for the other complex assets.
90

2.
ACQUISITIONS
Energy Harbor Business Combination
On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i)
Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary
of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly owned subsidiary of Vistra Vision, and
(iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue) exchanged a
portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively,
Energy Harbor Merger). The Energy Harbor Merger combined Energy Harbor's and Vistra's nuclear and retail businesses and
certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free
technologies (dispatchable and renewables/storage) and the retail business.
The Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805, Business
Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated
fair values on the Merger Date. The combined results of operations are reported in the consolidated financial statements
beginning as of the Merger Date.
The following table summarizes the acquisition date fair value of Energy Harbor associated with the Energy Harbor
Merger on the Merger Date:
Consideration
(in millions)
Cash consideration
$
3,100
15% of the fair value of net assets contributed to Vistra Vision by Vistra (a)
1,496
Total purchase price
4,596
Fair value of noncontrolling interest in Energy Harbor (b)
811
Acquisition date fair value of Energy Harbor
$
5,407
____________
(a)
Valued using a discounted cash flow analysis of the contributed subsidiaries including contributed debt.
(b)
Represents 15% of the acquisition date fair value implied from the fair value of consideration transferred.
As a result of the Energy Harbor Merger, Vistra maintained an 85% ownership interest in Vistra Vision and recorded the
remaining 15% equity interest as a noncontrolling interest in the consolidated balance sheets as of the Merger Date. On the
Merger Date, we reclassified the carrying value of assets contributed to Vistra Vision of $749 million from additional paid-in-
capital of Vistra (the controlling interest) to the noncontrolling interest in subsidiary.
91

Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and
adjustments to those measurements were made in the second, third and fourth quarters of 2024. Accounting guidance provides
that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that
additional information is obtained about the facts and circumstances that existed as of the acquisition date. The provisional fair
values assigned to assets acquired and liabilities assumed are as follows:
Fair Value as of
March 1, 2024
Measurement
Period Adjustments
recorded through
December 31, 2024
(in millions)
Cash and cash equivalents
$
35
$
5
Trade accounts receivables, inventories, prepaid expenses, and other current assets
544
6
Investments (a)
2,021
—
Property, plant, and equipment (b)
5,616
(4)
Identifiable intangible assets (c)
444
16
Commodity and other derivative contractual assets (d)
129
(11)
Other noncurrent assets
61
53
Total identifiable assets acquired
8,850
65
Trade accounts payable and other current liabilities
320
57
Long-term debt, including amounts due currently
413
—
Commodity and other derivative contractual liabilities (d)
179
—
Accumulated deferred income taxes
1,314
(50)
Asset retirement obligations (e)
1,368
—
Identifiable intangible liabilities
55
(18)
Other noncurrent liabilities and deferred credits
18
6
Total identifiable liabilities assumed
3,667
(5)
Identifiable net assets acquired
5,183
70
Goodwill (f)
224
(70)
Net assets acquired
$
5,407
____________
(a)
Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future
retirement and decommissioning of the PJM nuclear generation facilities. These investments include equity, debt and
other fixed-income securities consistent with investment rules established by the NRC. They are valued using a market
approach (Level 1 or Level 2 depending on security).
(b)
Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach.
The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).
(c)
Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately
five years compared with cash flows based on current market prices with the resulting difference discounted to present
value (Level 3). Also includes acquired retail customer relationships which are valued based on discounted cash flow
analysis of acquired customers and estimated attrition rates (Level 3).
(d)
Acquired derivatives are valued using the methods described in Note 11 (Level 1, Level 2, or Level 3). Contracts with
terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3).
(e)
Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers
multiple decommissioning methods and are based on decommissioning cost studies (Level 3).
(f)
The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is
recorded as goodwill. Goodwill represents expected synergies to be generated from combining operations of Energy
Harbor with Vistra. None of the Goodwill is deductible for income tax purposes.
92

The following unaudited pro forma financial information for the years ended December 31, 2024 and 2023 assumes that
the Energy Harbor Merger occurred on January 1, 2023. The unaudited pro forma financial information is provided for
informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the
Energy Harbor Merger been completed on January 1, 2023, nor is the unaudited pro forma financial information indicative of
future results of operations, which may differ materially from the pro forma financial information presented here.
Year Ended December 31,
2024
2023
(in millions)
Revenues
$
17,948
$
17,148
Net income
$
2,901
$
1,398
The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and
amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the
Energy Harbor Merger, effects of the Energy Harbor Merger on tax expense (benefit), and other related adjustments.
Determining the amounts of revenue and earnings of Energy Harbor since the acquisition date is impractical as operations have
been integrated into our commercial platform which is managed at a portfolio level.
Acquisition costs incurred in the Energy Harbor Merger totaled $25 million and $24 million for the year ended December
31, 2024 and 2023, respectively, and are classified as selling, general, and administrative expenses in the consolidated
statements of operations.
Acquisition of Noncontrolling Interest
On September 18, 2024, Vistra Operations and Vistra Vision Holdings I LLC, an indirect wholly owned subsidiary of
Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (the UPAs) with each of Nuveen
and Avenue, pursuant to which Vistra Vision Holdings agreed to purchase each of Nuveen's and Avenue's combined 15%
noncontrolling interest in Vistra Vision for approximately $3.2 billion in cash. The UPAs contained certain closing conditions
outside our control that represent conditional redemption obligations that required us to reflect the transaction as redeemable
noncontrolling interest within the mezzanine section of the consolidated balance sheet as of September 30, 2024. The UPAs
were amended prior to close to accelerate principal payments to Avenue and certain Nuveen noncontrolling interest holders.
The transaction closed on December 31, 2024 (Closing Date), with all closing conditions met. Upon closing, we reclassified the
remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation. See Note 9 for
additional information.
93

3.
REVENUE
Revenue Disaggregation
The following tables disaggregate our revenue by major source:
Year Ended December 31, 2024
Retail
Texas
East (a)
West
Asset
Closure
Eliminations
/ Corporate
and Other
Consolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT
$ 8,064
$
—
$
—
$
—
$
—
$
—
$
8,064
Retail energy charge in Northeast/Midwest (a)
3,595
—
—
—
—
—
3,595
Wholesale generation revenue from ISO/RTO
—
399
1,351
228
—
—
1,978
Capacity revenue from ISO/RTO (b)
—
—
74
—
—
—
74
Revenue from other wholesale contracts
—
422
398
230
—
—
1,050
Total revenue from contracts with
customers
11,659
821
1,823
458
—
—
14,761
Other revenues:
Transferable PTC revenues (c)
—
292
264
—
—
—
556
Hedging revenues — realized
1,241
(453)
31
84
(8)
—
895
Hedging revenue — unrealized
(168)
700
143
329
9
—
1,013
Intangible amortization and other revenues
1
—
(4)
—
—
2
(1)
Intersegment sales (d)
64
4,034
3,404
6
—
(7,508)
—
Total other revenues
1,138
4,573
3,838
419
1
(7,506)
2,463
Total revenues
$12,797
$ 5,394
$ 5,661
$
877
$
1
$
(7,506) $
17,224
____________
(a)
Includes ten months of revenue associated with operations acquired in the Energy Harbor Merger.
(b)
Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $126 million of capacity sold
offset by $52 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power
costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $139 million offset by
$116 million of capacity sold within the East segment.
(c)
Represents transferable PTCs generated from qualifying nuclear and solar assets during the period.
(d)
East segment includes $195 million of intersegment unrealized net losses, and Texas and West segments include
$74 million and $4 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of
commodity positions with the Retail segment.
94

Year Ended December 31, 2023
Retail
Texas
East
West
Asset
Closure
Eliminations
/ Corporate
and Other
Consolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT
$ 7,674
$
—
$
—
$
—
$
—
$
—
$
7,674
Retail energy charge in Northeast/Midwest
1,642
—
—
—
—
—
1,642
Wholesale generation revenue from ISO/
RTO
—
1,190
1,298
421
—
—
2,909
Capacity revenue from ISO/RTO (a)
—
—
98
—
—
—
98
Revenue from other wholesale contracts
—
505
797
179
—
—
1,481
Total revenue from contracts with
customers
9,316
1,695
2,193
600
—
—
13,804
Other revenues:
Transferable PTC revenues (b)
—
10
—
—
—
—
10
Hedging revenues — realized
1,063
(885)
43
67
(36)
—
252
Hedging revenue — unrealized
191
(714)
958
243
36
—
714
Intangible amortization and other revenues
2
—
(5)
—
—
2
(1)
Intersegment sales (c)
—
3,873
2,701
4
—
(6,578)
—
Total other revenues
1,256
2,284
3,697
314
—
(6,576)
975
Total revenues
$10,572
$ 3,979
$ 5,890
$
914
$
—
$
(6,576) $
14,779
____________
(a)
Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $233 million of capacity sold
offset by $135 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased
power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $82 million
offset by $73 million of capacity sold within the East segment.
(b)
Represents transferable PTCs generated from qualifying solar assets during the period.
(c)
East segment includes $814 million of intersegment unrealized net gains, and Texas and West segments include $48
million and $6 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity
positions with the Retail segment.
95

Year Ended December 31, 2022
Retail
Texas
East
West
Asset
Closure
Eliminations
/ Corporate
and Other
Consolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT
$ 6,971
$
—
$
—
$
—
$
—
$
—
$
6,971
Retail energy charge in Northeast/Midwest
2,139
—
—
—
—
—
2,139
Wholesale generation revenue from ISO/RTO
—
1,277
1,987
467
562
—
4,293
Capacity revenue from ISO/RTO (a)
—
—
76
—
27
—
103
Revenue from other wholesale contracts
—
696
1,256
151
22
—
2,125
Total revenue from contracts with
customers
9,110
1,973
3,319
618
611
—
15,631
Other revenues:
Hedging revenues — realized
875
(67)
(247)
35
(333)
1
264
Hedging revenue — unrealized
(532)
(637)
(770)
(326)
102
—
(2,163)
Intangible amortization and other revenues
2
—
(6)
—
—
—
(4)
Intersegment sales (b)
—
2,609
2,133
9
4
(4,755)
—
Total other revenues
345
1,905
1,110
(282)
(227)
(4,754)
(1,903)
Total revenues
$ 9,455
$ 3,878
$ 4,429
$
336
$
384
$
(4,754) $
13,728
____________
(a)
Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $361 million of capacity sold
offset by $285 million of capacity purchased. The Asset Closure segment includes $27 million of capacity sold. Net
capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated
statement of operations includes capacity purchased of $212 million offset by $167 million of capacity sold within the
East segment.
(b)
Texas and East segments include $780 million and $45 million, respectively, of intersegment unrealized net losses and
West and Asset Closure segments include $2 million and $4 million respectively, of intersegment unrealized net gains
from mark-to-market valuations of commodity positions with the Retail segment.
Retail Energy Charges
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes
delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 60 days from invoice date.
Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a
series of distinct services and are accounted for as a single performance obligation.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues
are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators
or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these
contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and
variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any
unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and
customer activity and therefore it is not practicable to estimate such amounts.
96

Wholesale Generation Revenue from ISOs/RTOs and Revenue from Other Wholesale Contracts
Wholesale generation revenue is recognized when volumes are delivered to the ISO/RTO. Other wholesale contracts
include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue
from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Wholesale revenues are recognized
over time using the output method based on kilowatt hours delivered or other applicable performance measurements and cash is
settled shortly after invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and
CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Wholesale revenues are delivered as
a series of distinct services and are accounted for as a single performance obligation. When electricity is sold to and purchased
from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale
generation revenues.
Capacity Revenue From ISO/RTO
We offer generation capacity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers.
Capacity ensures installed generation and demand response is available to satisfy system integrity and reliability requirements.
Capacity revenues are recognized when the performance obligation is satisfied ratably over time as our power generation
facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if the
facility is not available during the capacity period and are recorded as a reduction to revenue. When capacity is sold to and
purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in
capacity revenue from ISO/RTO.
Other Revenues
Other revenues, as included in the tables of disaggregated revenue above, represent amounts not accounted for under ASC
606, Revenue from Contracts with Customers and are comprised of the following:
•
Transferable production tax credit revenues accounted for as income-related grants by analogy to IAS 20 (see Note 4
for additional information).
•
Intangible amortization of acquired intangible liabilities related to retail and wholesale contracts (see Note 7 for
additional information).
•
Hedging revenue from electricity and natural gas derivative contracts accounted for under ASC 815, Derivatives and
Hedging, including the impact of realized and unrealized gains or losses on those contracts (see Note 11 for
additional information).
•
Intersegment sales are presented by segment and eliminated in consolidation.
Contract and Other Customer Acquisition Costs
We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life
of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition
rates. The deferred acquisition and contract cost balance as of December 31, 2024 and 2023 was $114 million and $97 million,
respectively. The amortization related to these costs during the years ended December 31, 2024, 2023, and 2022 totaled $97
million, $88 million, and $83 million respectively, recorded as SG&A expenses, and $6 million, $6 million, and $6 million,
respectively, recorded as a reduction to operating revenues in the consolidated statements of operations.
Practical Expedients
The majority of our revenues are recognized under the right to invoice practical expedient, which allows us to recognize
revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the
volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient.
We have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for
which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar
customer contracts with similar performance obligations. Sales taxes are not included in revenue.
97

Performance Obligations
As of December 31, 2024, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied,
relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers for
which the total consideration is fixed and determinable at contract execution. Capacity revenues are recognized as the
performance obligations to make capacity available to the related ISOs/RTOs or counterparties are met.
2025
2026
2027
2028
2029
2030 and
Thereafter
Total
(in millions)
Remaining performance obligations
$
1,123
$
825
$
289
$
122
$
62
$
548
$
2,969
Trade Accounts Receivable
December 31,
2024
December 31,
2023
(in millions)
Wholesale and retail trade accounts receivable
$
2,061
$
1,735
Allowance for credit losses
(79)
(61)
Trade accounts receivable — net
$
1,982
$
1,674
Trade accounts receivable from contracts with customers — net
$
1,514
$
1,239
Other trade accounts receivable — net
468
435
Total trade accounts receivable — net
$
1,982
$
1,674
Gross trade accounts receivable as of December 31, 2024 and December 31, 2023 include unbilled retail revenues of $802
million and $614 million, respectively.
Allowance for Credit Losses on Accounts Receivable
Year Ended December 31,
2024
2023
2022
(in millions)
Allowance for credit losses on accounts receivable at beginning of period
$
61
$
65
$
45
Increase for bad debt expense
183
164
179
Decrease for account write-offs
(165)
(168)
(159)
Allowance for credit losses on accounts receivable at end of period
$
79
$
61
$
65
4.
GOVERNMENT ASSISTANCE
Inflation Reduction Act of 2022 (IRA)
In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy
tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC,
and a first-time stand-alone battery storage investment tax credit. The section 45U nuclear PTC provides a federal tax credit of
up to $15 per MWh, subject to phase out as power prices increase above $25 per MWh, to existing nuclear facilities from 2024
through 2032 subject to an annual inflation adjustment. The Company accounts for transferable ITCs and PTCs we expect to
receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and
Disclosures of Government Assistance.
98

Transferable PTCs
In the year ended December 31, 2024, we recognized transferable nuclear PTC revenues of $545 million and transferable
solar PTC revenues of $11 million. Our nuclear PTC revenues are an estimate based on gross receipts generated from
qualifying nuclear production in 2024 and reflect our determination that we will meet the prevailing wage requirements
necessary to earn the five times multiplier at all of our nuclear units. Our computation of gross receipts includes settled spot
energy revenues and capacity revenues at each nuclear unit, and excludes any hedges. Treasury regulations are expected to
further define the scope of the legislation in many important respects over the next year, including interpretive guidance on the
definition of gross receipts for the nuclear PTC. Any interpretive guidance on the definition of gross receipts which differs from
the interpretation used in our estimate could result in a material change to PTC revenues attributable to 2024 and would be
reflected as a change in estimate in the period in which the guidance is received.
Transferable ITCs
In June 2023, our 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III) in California
commenced commercial operations. As a result of Moss Landing Phase III meeting requirements to be placed in service in
June 2023, we recognized $154 million of transferable ITCs associated with the project in other noncurrent assets in the
consolidated balance sheet. In September 2024, we recognized an additional $2 million of transferable ITCs associated with the
project and reclassified the $156 million of credits to other current assets.
In December 2024, our Baldwin 68 MW solar / 2 MW battery ESS and Coffeen 44 MW solar / 2 MW battery ESS
facilities in Illinois met requirements to be placed in service. As a result, we recognized $57 million and $45 million of
transferable ITCs associated with the projects, respectively, in other noncurrent assets in the consolidated balance sheet.
Sales of Transferable PTCs and ITCs
In October 2024, we sold $156 million of transferable ITCs and $10 million of transferable solar PTCs generated in 2023.
Vistra received cash consideration from the sale in October 2024.
In January 2025, we sold $200 million of transferable nuclear PTCs we recognized from qualifying 2024 nuclear
production. Cash consideration from the sale will be received in installments through July 2025 with an initial payment
received in January 2025.
5.
INCOME TAXES
Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra serves as the
corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and
published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the
taxes of such group.
Income Tax Expense (Benefit)
The components of our income tax expense (benefit) are as follows:
Year Ended December 31,
2024
2023
2022
(in millions)
Current:
U.S. Federal
$
2
$
(1) $
2
State
46
52
7
Total current
48
51
9
Deferred:
U.S. Federal
561
421
(304)
State
46
36
(55)
Total deferred
607
457
(359)
Total
$
655
$
508
$
(350)
99

Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded:
Year Ended December 31,
2024
2023
2022
(in millions)
Income (loss) before income taxes
$
3,467
$
2,000
$
(1,560)
U.S. federal statutory rate
21 %
21 %
21 %
Income taxes at the U.S. federal statutory rate
728
420
(328)
State tax, net of federal benefit
80
86
(19)
Nondeductible TRA accretion
2
41
18
Transferable PTC revenues
(115)
(2)
—
Equity awards
(53)
(3)
(3)
Valuation allowance
(2)
(20)
(8)
Release of Uncertain Tax Positions
—
(35)
—
Other
15
21
(10)
Income tax expense (benefit)
$
655
$
508
$
(350)
Effective tax rate
18.9 %
25.4 %
22.4 %
Deferred Income Tax Balances
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2024 and 2023 are
as follows:
December 31,
2024
2023
(in millions)
Noncurrent Deferred Income Tax Assets
Tax credit carryforwards
$
86
$
84
Loss carryforwards
949
1,081
Identifiable intangible assets
340
380
Long-term debt
225
173
Employee benefit obligations
133
117
Commodity contracts and interest rate swaps
383
664
Other
36
33
Total deferred tax assets
$
2,152
$
2,532
Noncurrent Deferred Income Tax Liabilities
Property, plant, and equipment
2,765
1,264
Total deferred tax liabilities
2,765
1,264
Valuation allowance
75
46
Net Deferred Income Tax Asset (Liability)
$
(688) $
1,222
As of December 31, 2024, we had total net deferred tax liabilities of approximately $688 million that were substantially
comprised of book and tax basis differences related to our generation and mining property, plant, and equipment, partially
offset by federal and state net operating loss (NOL) carryforwards. Our net deferred tax liabilities were significantly impacted
by the Energy Harbor Merger. For the years ended December 31, 2024 and 2023, we recognized tax benefits of $2 million and
$20 million primarily related to the release of the federal valuation allowance on charitable contributions and state valuation
allowances, respectively. As of December 31, 2024, we assessed the need for a valuation allowance related to our deferred tax
asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. We
have identified positive evidence in the form of cumulative income on an unadjusted basis over the preceding 12 quarters. We
evaluated historical earnings, performed scheduling of the reversal of temporary differences, and considered other positive and
negative evidence. In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax
assets will be fully utilized by future taxable income, and thus no valuation allowance was required. A valuation allowance of
approximately $30 million was recorded as part of Energy Harbor purchase accounting on state NOL carryforwards.
100

As of December 31, 2024, we had $3.2 billion pre-tax net operating loss (NOL) carryforwards for federal income tax
purposes that will begin to expire in 2031.
The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax
liabilities of $4 million and zero at December 31, 2024 and 2023, respectively.
IRA
In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy
tax credits, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise
tax on net stock repurchases. We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to
corporations with a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the
CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development
pipeline into account when forecasting cash taxes. See Notes 1 and 4 for additional information.
Final Section 163(j) Regulations
The final Section 163(j) regulations, which limits qualified deductions for business interest expense, were issued in July
2020 and provided a critical correction to the proposed regulations regarding the computation of adjusted taxable income. As of
January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the add-back of depreciation
and amortization to adjusted taxable income. As a result, under the law as currently enacted, Vistra's deductible business
interest expense was significantly limited for the 2024 tax year and will continue to be so limited under current law going
forward. Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and
make permanent the add-back of depreciation and amortization to adjusted taxable income.
Liability for Uncertain Tax Positions
Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed
and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to
the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.
We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were
immaterial for the years ended December 31, 2024, 2023, and 2022. The following table summarizes the changes to the
uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance
sheets for the years ended December 31, 2024, 2023, and 2022.
Year Ended December 31,
2024
2023
2022
(in millions)
Balance at beginning of period, excluding interest and penalties
$
—
$
36
$
38
Additions based on tax positions related to prior years
4
—
—
Reductions based on tax positions related to prior years
—
—
(1)
Reductions related to the lapse of the tax statute of limitations
—
(35)
—
Settlements with taxing authorities
—
(1)
(1)
Balance at end of period, excluding interest and penalties
$
4
$
—
$
36
Vistra and its subsidiaries file income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject
to examinations by the IRS and other taxing authorities. In February 2021, Vistra was notified that the IRS had opened a federal
income tax audit for tax years 2018 and 2019. The federal income tax audit was closed in June 2023 with immaterial changes.
Uncertain tax positions totaled $4 million and zero as of December 31, 2024 and 2023, respectively. Of the amounts recorded
as unrecognized tax benefits, an insignificant portion would impact our effective tax rate if recognized.
Tax Matters Agreement
On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to
take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to
indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.
101

Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off
between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra is generally required to reimburse EFH Corp. with
respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with
respect to any taxes paid by us that are attributable to EFH Corp.
We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing
authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of
EFH Corp.'s net operating loss deductions.
Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be
expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we
obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off.
Certain of these restrictions apply for two years after the Spin-Off.
Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from
EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we
obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d)
we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp.
that the action will not affect the intended tax treatment of the Spin-Off.
6.
PROPERTY, PLANT, AND EQUIPMENT
Our property, plant, and equipment consist of our power generation assets, related mining assets, land, information
system hardware, capitalized corporate office lease space and other leasehold improvements. The estimated remaining useful
lives of our property, plant, and equipment ranges from 1 to 29 years. Land is not depreciated.
December 31,
2024
2023
(in millions)
Power generation and structures
$
22,783
$
17,297
Land
603
572
Office and other equipment
160
159
Total
23,546
18,028
Less accumulated depreciation
(8,020)
(6,657)
Net of accumulated depreciation
15,526
11,371
Finance lease right-of-use assets (net of accumulated amortization)
153
160
Nuclear fuel (net of accumulated amortization of $409 million and $120 million)
1,434
379
Construction work in progress
1,060
522
Property, plant, and equipment — net
$
18,173
$
12,432
Depreciation expenses totaled $1.670 billion, $1.344 billion, and $1.388 billion for the years ended December 31, 2024,
2023, and 2022, respectively.
102

Retirement of Generation Facilities
The following are all of our facilities that have either been retired, or that have announced retirement dates. Operation
results for plants with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year
the retirement is expected to occur.
Facility
Location
ISO/RTO
Fuel Type
Net Generation
Capacity (MW)
Announced Retirement Date (a)
Segment
Baldwin
Baldwin, IL
MISO
Coal
1,185
By the end of 2027
East
Coleto Creek
Goliad, TX
ERCOT
Coal
650
By the end of 2027 (b)
Texas
Kincaid
Kincaid, IL
PJM
Coal
1,108
By the end of 2027
East
Miami Fort
North Bend, OH
PJM
Coal
1,020
By the end of 2027
East
Newton
Newton, IL
MISO
Coal
615
By the end of 2027
East
Edwards
Bartonville, IL
MISO
Coal
585
Retired January 1, 2023
Asset Closure
Joppa
Joppa, IL
MISO
Coal
802
Retired September 1, 2022
Asset Closure
Joppa
Joppa, IL
MISO
Natural Gas
221
Retired September 1, 2022
Asset Closure
Zimmer
Moscow, OH
PJM
Coal
1,300
Retired June 1, 2022
Asset Closure
Total
7,486
____________
(a) Generation facilities may retire earlier than expected dates disclosed if economic or other conditions dictate.
(b) Following the retirement of Coleto Creek as a coal-fueled plant, the Company intends to repower it as a gas-fueled plant.
Impairment of Long-Lived Assets
In the first quarter of 2023, we recognized an impairment loss of $49 million related to our Kincaid generation facility in
Illinois as a result of a significant decrease in the projected operating margins of the facility, primarily driven by a decrease in
projected power prices.
The impairment is reported in our East segment and includes write-downs of property, plant, and
equipment of $45 million, write-downs of inventory of $2 million, and write-downs of operating lease right-of-use assets of $2
million.
In the fourth quarter of 2022, we recognized an impairment loss of $74 million related to our Miami Fort generation
facility in Ohio as a result of a significant decrease in the projected operating margins of the facility, reflecting an increase in
projected coal costs along with a decrease in projected power prices. The impairment is reported in our East segment and
includes write-downs of property, plant, and equipment of $71 million and write-downs of inventory of $3 million.
In determining the fair value of the impaired asset groups in 2023 and 2022, we utilized the income approach described in
ASC 820, Fair Value Measurement.
7.
GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
As of December 31, 2024 and 2023, the carrying value of goodwill totaled $2.807 billion and $2.583 billion, respectively.
Retail Segment
Texas Segment
Retail Reporting
Unit (a)
Texas Generation
Reporting Unit
Total Goodwill
(in millions)
Balance at December 31, 2023
$
2,461
$
122
$
2,583
Goodwill recorded in connection with the Energy Harbor Merger (b)
224
Balance at December 31 2024
$
2,461
$
122
$
2,807
____________
(a) Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight-line basis.
(b) Allocation of goodwill attributable to the Energy Harbor acquisition to reporting units is pending completion of purchase
accounting measurement period.
103

Goodwill is required to be evaluated for impairment at least annually or whenever events or changes in circumstances
indicate an impairment may exist. We have selected October 1 as our annual goodwill test date. On the most recent goodwill
testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and
Texas Generation reporting units exceeded their carrying value at October 1, 2024. Significant qualitative factors evaluated
included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions,
cost factors, customer attrition, interest rates, market capitalization, and changes in reporting unit book value.
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
December 31, 2024
December 31, 2023
Identifiable Intangible Asset
Gross
Carrying
Amount
Accumulated
Amortization
Net
Gross
Carrying
Amount
Accumulated
Amortization
Net
(in millions)
Retail customer relationship
$
2,173
$
1,977
$
196
$
2,088
$
1,866
$
222
Software and other technology-related assets
601
293
308
536
315
221
Retail and wholesale contracts
503
353
150
233
217
16
Long-term service agreements
18
5
13
18
5
13
Other identifiable intangible assets (a)
218
13
205
62
11
51
Total identifiable intangible assets subject to
amortization
$
3,513
$
2,641
872
$
2,937
$
2,414
523
Retail trade names (not subject to amortization)
1,341
1,341
Total identifiable intangible assets
$ 2,213
$ 1,864
____________
(a) Includes mining development costs and environmental allowances (emissions allowances and renewable energy
certificates).
Identifiable intangible liabilities are comprised of the following:
Year Ended December 31,
Identifiable Intangible Liability
2024
2023
(in millions)
Long-term service agreements
$
108
$
122
Wholesale power and fuel purchase contracts
47
9
Total identifiable intangible liabilities
$
155
$
131
104

Amortization of finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated
statements of operations) consisted of:
Identifiable Intangible Assets/
Liabilities
Consolidated Statements of
Operations
Remaining useful
lives of identifiable
intangible assets at
December 31,
2024 (weighted
average in years)
Year Ended December 31,
2024
2023
2022
(in millions)
Retail customer relationship
Depreciation and
amortization
2
$
111
$
98
$
137
Software and other
technology-related assets
Depreciation and
amortization
3
60
58
69
Retail and wholesale
contracts
Operating revenues/Fuel,
purchased power costs,
and delivery fees
3
(12)
8
7
Other identifiable intangible
assets
Fuel, purchased power
costs, and delivery fees/
Depreciation and
amortization
4
414
357
391
Total intangible asset expense, net
$
573
$
521
$
604
Amounts recorded in depreciation and amortization totaled $173 million, $158 million, and $208 million for the years
ended December 31, 2024, 2023, and 2022, respectively. Amounts include all expenses associated with environmental
allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which
are presented in fuel, purchased power costs, and delivery fees in the consolidated statements of operations. Emissions
allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued
as retail electricity delivery occurs.
The following is a description of the separately identifiable intangible assets recorded in fresh start reporting and in
connection with purchase accounting from acquisitions.
•
Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-
contracted retail customer base, including residential and business customers, and is amortized using an accelerated
method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are
realized over their estimated useful life.
•
Retail and wholesale contracts — These intangible assets and liabilities represent the value of various acquired retail
and wholesale contracts and fuel and transportation purchase contracts. The contracts were identified as either assets
or liabilities based on the respective fair values utilizing prevailing market prices for commodities or services
compared to the fixed prices contained in these agreements. The intangible assets or liabilities are amortized in
relation to the economic terms of the related contracts.
•
LTSA — Our acquired LTSA intangibles represent the estimated fair value of favorable or unfavorable contract
obligations with respect to long-term plant maintenance agreements and are amortized based on the expected usage of
the service agreements over the contract terms. The majority of the plant maintenance services relate to capital
improvements and the related amortization of the plant maintenance agreements is recorded to property, plant, and
equipment.
•
Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including
the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield Energy, Dynegy Energy Services,
TriEagle Energy, Public Power, and U.S. Gas & Electric, and were determined to be indefinite-lived assets not
subject to amortization. These intangible assets are evaluated for impairment at least annually in accordance with
accounting guidance related to other indefinite-lived intangible assets. We have selected October 1 as our test date.
Significant qualitative factors evaluated included trade name financial performance, general macroeconomic,
industry, and market conditions, customer attrition and interest rates. On the most recent testing date, we determined
that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value
at October 1, 2024.
105

Estimated Amortization of Identifiable Intangible Assets
As of December 31, 2024, the estimated aggregate amortization expense of identifiable intangible assets, excluding
environmental allowances, for each of the next five fiscal years is as shown below.
Year
Estimated Amortization Expense
(in millions)
2025
$
231
2026
$
167
2027
$
72
2028
$
51
2029
$
34
8.
COLLATERAL FINANCING AGREEMENT WITH AFFILIATE
On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed
by the Company (the Trust) that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial
purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-
Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of
Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the
direction of Vistra Operations, the Eligible Assets held by the Trust can be (i) delivered to one or more designated subsidiaries
of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with
counterparties, and/or (ii) pledged as collateral support for a letter of credit program.
Under the Facility Agreement, Vistra Operations has the right (Issuance Right), from time to time, to require the Trust to
purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% Senior Secured
Notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury
Strips corresponding to the portion of the issuance right exercised at such time.
The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders
of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to
repurchase.
Vistra Operations pays a facility fee (Facility Fee) to the Trust payable on each May 17 and November 17, commencing
on November 17, 2023, to and including May 17, 2028 (each, a Distribution Date), and on certain other dates as provided in the
Facility Agreement. The Facility Fee is generally calculated at a rate of 3.3608% per annum, applied to the maximum amount
of 7.233% Senior Secured Notes that Vistra Operations could issue and sell to the Trust under the Facility Agreement as of the
close of business on the business day immediately preceding the applicable Distribution Date.
As of December 31, 2024 and 2023, the fair value of Eligible Assets held by counterparties to satisfy current and future
margin deposit requirements totaled $435 million and $439 million, respectively, and is reported in the consolidated balance
sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.
106

9.
DEBT, CREDIT FACILITIES, AND FINANCINGS
Amounts in the table below represent the categories of debt obligations incurred by the Company.
December 31,
2024
2023
(in millions)
Long-term debt, including amounts due currently:
Project-level debt
$
1,064
$
—
Vistra Operations debt
15,405
14,517
Long-term debt before unamortized premiums, discounts, and issuance costs
16,469
14,517
Unamortized premiums, discounts, and issuance costs
(171)
(115)
Long-term debt including debt due currently
$
16,298
$
14,402
Accounts receivable financing
$
750
$
—
Forward repurchase obligation
$
1,335
$
—
107

Long-Term Debt
Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently,
incurred by the Company.
December 31,
2024
2023
(in millions)
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030
$
2,475
$
2,500
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026
367
—
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031
697
—
Vistra Operations Senior Secured Notes:
4.875% Senior Secured Notes, due May 13, 2024
—
400
3.550% Senior Secured Notes, due July 15, 2024
—
1,500
5.125% Senior Secured Notes, due May 13, 2025
744
1,100
5.050% Senior Secured Notes, due December 30, 2026
500
—
3.700% Senior Secured Notes, due January 30, 2027
800
800
4.300% Senior Secured Notes, due July 15, 2029
800
800
6.950% Senior Secured Notes, due October 15, 2033
1,050
1,050
6.000% Senior Secured Notes, due April 15, 2034
500
—
5.700% Senior Secured Notes, due December 30, 2034
750
—
Total Vistra Operations Senior Secured Notes
5,144
5,650
Energy Harbor Revenue Bonds:
3.375% Revenue Bond, due August 1, 2029
100
—
4.750% Revenue Bond, due June 1, 2033 and July 1, 2033
285
—
3.750% Revenue Bond, due October 1, 2047
46
—
Total Energy Harbor Revenue Bonds
431
—
Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026
1,000
1,000
5.625% Senior Unsecured Notes, due February 15, 2027
1,300
1,300
5.000% Senior Unsecured Notes, due July 31, 2027
1,300
1,300
4.375% Senior Unsecured Notes, due May 15, 2029
1,250
1,250
7.750% Senior Unsecured Notes, due October 15, 2031
1,450
1,450
6.875% Senior Unsecured Notes, due April 15, 2032
1,000
—
Total Vistra Operations Senior Unsecured Notes
7,300
6,300
Other:
Equipment Financing Agreements
55
67
Total other long-term debt
55
67
Unamortized debt premiums, discounts, and issuance costs
(171)
(115)
Total long-term debt including amounts due currently
16,298
14,402
Less amounts due currently
(880)
(2,286)
Total long-term debt less amounts due currently
$
15,418
$
12,116
108

Long-Term Debt Maturities
Long-term debt maturities at December 31, 2024 are as follows:
December 31, 2024
(in millions)
2025
$
885
2026
1,792
2027
3,427
2028
27
2029
2,177
Thereafter
8,161
Unamortized premiums, discounts, and debt issuance costs
(171)
Total long-term debt, including amounts due currently
$
16,298
Credit Facilities
Our credit facilities and related available capacity at December 31, 2024 are presented below.
December 31, 2024
Credit Facilities
Maturity Date
Facility
Limit
Cash
Borrowings
(Long-Term
Debt, Including
Amounts Due
Currently)
Letters of Credit
Outstanding
Available
Capacity
(in millions)
Vistra Operations debt:
Revolving Credit Facility
October 11, 2029
$
3,440
$
—
$
1,278
$
2,162
Term Loan B-3 Facility
December 20, 2030
2,475
2,475
—
—
Total Vistra Operations Credit Facilities
$
5,915
$
2,475
$
1,278
$
2,162
Vistra Operations Commodity-Linked Facility
October 1, 2025
1,750
—
—
771
Total Vistra Operations debt
$
7,665
$
2,475
$
1,278
$
2,933
Project-level debt:
Tax Credit Bridge Loan
November 1, 2025
106
106
—
—
Tax Credit Bridge Loan
December 3, 2026
261
261
—
—
BCOP Credit Facility
367
367
—
—
Vistra Zero Term Loan B Facility (a)
April 30, 2031
697
697
—
—
Total project-level debt
$
1,064
$
1,064
$
—
$
—
Total credit facilities
$
8,729
$
3,539
$
1,278
$
2,933
____________
(a) Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero
Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries.
109

Vistra Operations Credit Facilities
Vistra maintains credit facilities with certain financial institutions and, as of December 31, 2024, has aggregate
commitments of up to $5.915 billion in senior secured, first-lien revolving credit commitments and outstanding term loans
(Vistra Operations Credit Facilities). The Vistra Operations Credit Facilities consist of (i) revolving credit commitments of up
to $3.440 billion, including aggregate revolving letter of credit commitments of up to $3.440 billion (Revolving Credit
Facility), and (ii) term loans of $2.475 billion (Term Loan B-3 Facility). These amounts reflect the following transactions and
amendments completed in 2024:
Amendment Date
Key Changes
December 2024
Lowered fixed spread on Term Loan B-3 Facility borrowings from 2.00% to 1.75%
October 2024
Increased Revolving Credit Facility commitments from $3.175 billion to $3.440 billion
Extended the maturity date of the Revolving Credit Facility to October 11, 2029
Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes. Under the Vistra
Operations Credit Agreement, the interest on borrowings under the Revolving Credit Facility is paid based on (i) the forward-
looking term rate based on SOFR (Term SOFR) plus a spread that will range from 1.25% to 2.00% and (ii) the fee on any
undrawn amounts with respect to the Revolving Credit Facility ranges from 17.5 basis points to 35.0 basis points. Interest
periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid in arrears. Letters of credit
issued under the Revolving Credit Facility bear interest that ranges from 1.25% to 2.00% and are paid quarterly in arrears.
Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt
securities. As of December 31, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-
linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn
amounts relating to such commitments were 1.725% and 27.0 basis points, respectively, and the applicable interest rate margin
for the letters of credit issued under the Revolving Credit Facility was 1.725%.
Term Loan B-3 Facility — The Term Loan B-3 Facility is used for general corporate purposes and bears interest based on
the applicable Term SOFR, plus a fixed spread of 2.00% through December 9, 2024 and 1.75% thereafter, and the weighted
average interest rates before taking into consideration interest rate swaps (see Note 11) on outstanding borrowings of $2.475
billion was 6.11% as of December 31, 2024. Interest periods for Term SOFR loans are for a one-, three-, or six-month periods
with interest paid in arrears. Cash borrowings under the Term Loan B-3 Facility are subject to required scheduled quarterly
payments of $6.25 million. Amounts paid cannot be reborrowed.
Other Information — Obligations under the Vistra Operations Credit Facilities are secured by liens covering substantially
all of Vistra Operations' (and certain of its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions
set forth in the Vistra Operations Credit Facilities. The Vistra Operations Credit Agreement includes certain collateral
suspension provisions that would take effect upon Vistra Operations achieving unsecured investment grade ratings from two
ratings agencies and there being no Term Loans (under and as defined in the Vistra Operations Credit Agreement) then
outstanding (or the holders thereof agreeing to release such security interests). Such collateral suspension provisions would
continue to be in effect unless and until Vistra Operations no longer holds unsecured investment grade ratings from at least two
ratings agencies, at which point collateral reversion provisions would take effect (subject to a 60-day grace period).
The Vistra Operations Credit Facilities also permit certain hedging agreements and cash management agreements to be
secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements and cash
management agreements meet certain criteria set forth in the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations
(and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the
agent under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting
Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets,
pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit
Facilities. The Vistra Operations Credit Agreement also includes a springing financial covenant with respect to the Revolving
Credit Facility that, when applicable, would require compliance with a consolidated first lien net leverage ratio. Vistra
Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary
conditions precedent set forth therein.
110

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default
resulting from non-payment of principal, interest, or fees when due, material breaches of representations and warranties,
breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other
agreements or instruments and the existence of material unpaid (or unstayed) judgments against Vistra Operations and certain
of its subsidiaries. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal,
interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of
specified lenders.
The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any
direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2024, Vistra
Operations can distribute approximately $8.2 billion to Parent under the Vistra Operations Credit Agreement without the
consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions
made by Vistra Operations to Parent of approximately $1.705 billion, $1.625 billion, and $1.775 billion during the years ended
December 31, 2024, 2023, and 2022, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts
sufficient for Parent to pay any taxes or general operating or corporate overhead expenses arising out of Parent's ownership or
operation of Vistra Operations. As of December 31, 2024, all of the restricted net assets of Vistra Operations may be distributed
to Parent.
Vistra Operations Commodity-Linked Revolving Credit Facility
As of December 31, 2024, Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-
Linked Facility) totaled $1.75 billion of aggregate available commitments. We have the flexibility, subject to our ability to
obtain additional commitments, to further increase the size of the Commodity-Linked Facility to $3.0 billion. As of December
31, 2024, the borrowing base of $771 million is lower than the facility limit which represents the aggregate commitments of
$1.75 billion. These amounts reflect the following amendment completed in 2024:
Amendment Date
Key Changes
October 2024
Increased the aggregate available commitments to $1.75 billion
Extended the maturity date to October 1, 2025
Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical
transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain
power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. Vistra
Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if
outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce
outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use any borrowings
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.
Interest on the Commodity-Linked Facility bears interest (i) based on either the Term SOFR or a daily simple SOFR rate,
(ii) a spread that ranges from 1.25% to 2.00%, and (iii) sustainability pricing adjustments based on certain sustainability-linked
targets and thresholds. Interest periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid
in arrears. The interest period for a daily simple SOFR is for a one-week period with interest paid in arrears. The fee on any
undrawn amounts with respect to the Commodity-Linked Facility ranges from 17.5 basis points to 35.0 basis points. As of
December 31, 2024, the applicable interest rate margins for borrowings outstanding under the Commodity-Linked Facility was
1.725% and the fee on any undrawn amounts with respect to the Commodity-Linked Facility was 27.0 basis points. Interest and
fees on the Commodity-Linked Facility are based on ratings of Vistra Operations' senior secured long-term debt securities.
BCOP Project-level Credit Facilities
In December 2024, BCOP and its subsidiaries entered into the BCOP Credit Agreement to fund the development of the
Baldwin and Coffeen solar generation and battery ESS facilities and the Oak Hill and Pulaski solar generation facilities in
Illinois and Texas. The BCOP Credit Agreement provides for (i) tax credit bridge loans of $367 million for the Oak Hill and
Pulaski projects (Tax Credit Bridge Loans) and (ii) construction/term loan commitments of $528 million and debt service
reserve letter of credit facility commitments of $29 million for all four facilities.
111

At December 31, 2024, the Tax Credit Bridge Loans for Oak Hill and Pulaski totaled $106 million and $261 million,
respectively, and mature in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit
Agreement. The weighted average interest rate on outstanding borrowings was 5.984% at December 31, 2024. Repayment of
the Tax Credit Bridge Loans are guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated
by the projects. At December 31, 2024, there were no construction/term loan borrowings outstanding or debt service reserve
letters of credit issued.
Interest is paid on the Tax Credit Bridge Loan in arrears based on the applicable Term SOFR rate elected in the borrowing
notice plus a fixed spread of 1.625% per annum. Interest on the construction/term loans will be paid in arrears based on the
applicable Term SOFR rate elected in the borrowing notice plus fixed spreads of 1.875% per annum for construction loans and
2.000% per annum for term loans. Fees on the debt service reserve letter of credit loans will be paid in arrears at 2.000% per
annum. Commitment fees on the undrawn loan commitments and unissued letter of credit commitments will pay quarterly in
arrears at a fixed percentage of the loan's fixed spread.
Vistra Zero Project-level Credit Agreement
In March 2024, Vistra Zero Operations entered into the Vistra Zero Credit Agreement. The Vistra Zero Credit Agreement
provides for a senior secured term loan (Term Loan B Facility) of up to $700 million, which Vistra Zero Operations borrowed
in its entirety in March 2024. Net proceeds of $690 million were used (i) to pay issuance costs and (ii) for working capital and
general corporate purposes. Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by
subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. These
amounts reflect the following amendment completed in 2024:
Amendment Date
Key Changes
December 2024
Lowered the fixed spread interest applicable to the Term Loan B Facility from 2.75% to 2.00%
Removed required scheduled quarterly payment requirements
Interest on the Term Loan B Facility is based on Term SOFR plus 2.75% per year through December 16, 2024. The
December 2024 amendment lowered the fixed spread on this instrument to 2.00% thereafter. Interest periods for Term SOFR
loans are for a one-, three-, or six-month periods with interest paid in arrears. The weighted average interest rates before taking
into consideration interest rate swaps on outstanding borrowings of $697 million was 6.36% as of December 31, 2024.
The Vistra Zero Credit Agreement contains customary covenants and warranties which are generally consistent in scope
with the Vistra Operations Credit Agreement, except that there is no financial maintenance covenant in the Vistra Zero Credit
Agreement.
Letter of Credit Facilities
Vistra Operations Secured Letter of Credit Facilities
Between August 2020 and July 2024, we entered into uncommitted standby letter of credit facilities with various banks
(each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first
lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra
Operations Credit Facilities). The Secured LOC Facilities may be renewed annually and are used for general corporate
purposes. As of December 31, 2024, $1.157 billion of letters of credit were outstanding under the Secured LOC Facilities.
Vistra Operations Unsecured Alternative Letter of Credit Facilities
In March 2024, we entered into unsecured alternative letter of credit facilities (Alternative LOC Facilities) to be used for
general corporate purposes. In May 2024, the Alternative LOC Facilities were amended to increase the commitment cap to a
total of $500 million. As of December 31, 2024, the total capacity was $500 million and $500 million of letters of credit were
outstanding under the Alternative LOC Facilities. The commitments under the Alternative LOC Facilities terminate in
December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities.
112

Vistra Operations Senior Secured Notes
Vistra Operations issues and sells its senior secured notes in offerings to eligible purchasers under Rule 144A and
Regulation S under the Securities Act (collectively, the Senior Secured Notes). The indenture (as may be amended or
supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the Senior Secured Notes provides
for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the
Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-priority security interest in the same
collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities and contains certain
covenants and restrictions consistent with the Vistra Operations Credit Facilities.
In December 2024, Vistra Operations issued $1.25 billion aggregate principal amount of senior secured notes, consisting
of $500 million aggregate principal amount of 5.050% senior secured notes due 2026 (5.050% Senior Secured Notes) and $750
million aggregate principal amount of 5.700% senior secured notes due 2034 (5.700% Senior Secured Notes) in an offering to
eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in
arrears on June 30 and December 30 beginning June 30, 2025. Net proceeds totaling approximately $1.240 billion, together
with cash on hand, will be used for (i) general corporate purposes, including to refinance outstanding indebtedness (including
2025 debt maturities), (ii) to fund the opportunistic early payout of the purchase price installment payments scheduled to be
paid in 2025 and 2026 to Avenue for the acquisition of the noncontrolling interest in Vistra Vision and (iii) to pay fees and
expenses related to the offering.
In May 2024 and July 2024, the 4.875% senior secured notes due May 2024 and 3.550% senior secured notes due July
2024, respectively, were repaid at maturity.
In April 2024, Vistra Operations issued $500 million aggregate principal amount of 6.000% senior secured notes due 2034
(6.000% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities
Act. Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net proceeds
totaling approximately $495 million, together with proceeds from the April 2024 issuance of 6.875% Senior Unsecured Notes
discussed below and cash on hand, were to be used for general corporate purposes, including to refinance outstanding
indebtedness (the senior secured debt maturities in May 2024 and July 2024).
Energy Harbor Revenue Bonds
Various governmental entities in Ohio and Pennsylvania have issued multiple tranches of revenue bonds for the benefit of
Energy Harbor Generation LLC (EHG) or Energy Harbor Nuclear Generation LLC (EHNG); (collectively, the EH entities), in
an aggregate principal amount of $431 million. The relevant EH entity is obligated to provide contractual payments to the
applicable issuer of the revenue bonds to service the principal and interest on the revenue bonds, the payment of which is
indirectly secured by all or substantially all of the assets of the EH entities under various mortgage bonds issued by the EH
entities. In the event of a default by the EH entities of their contractual obligation to pay principal and interest in respect of the
revenue bonds, the trustee of the revenue bonds would be able to call the mortgage bonds due and, if unpaid, foreclose on the
assets securing the mortgage bonds. The obligations of the EH entities in respect of the revenue bonds and related mortgage
bonds are guaranteed on an unsecured basis by Energy Harbor and Vistra.
Vistra Operations Senior Unsecured Notes
Vistra Operations issues and sells its senior unsecured notes in offerings to eligible purchasers under Rule 144A and
Regulation S under the Securities Act (collectively, the Senior Unsecured Notes). The indentures (as may be amended or
supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the Senior Unsecured Notes
provide for the full and unconditional guarantee by the Guarantor Subsidiaries. The Vistra Operations Senior Unsecured
Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations
and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially
all of their assets.
In April 2024, Vistra Operations issued $1.0 billion aggregate principal amount of 6.875% senior unsecured notes due
2032 (6.875% Senior Unsecured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the
Securities Act. Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net
proceeds totaling approximately $990 million, together with proceeds from the April 2024 issuance of 6.000% Senior Secured
Notes discussed above and cash on hand, were to be used for general corporate purposes, including to refinance outstanding
indebtedness (including the senior secured debt maturities in May 2024 and July 2024).
113

Other Debt Activity
Senior Secured Notes Tender Offer
In January 2024, Vistra Operations used the net proceeds from (i) the December 2023 issuances of the 6.950% senior
secured notes due 2033 and 7.750% senior unsecured notes due 2031 and (ii) cash on hand, to fund a cash tender offer (Senior
Secured Notes Tender Offer) to purchase for cash $759 million aggregate principal amount of certain notes, including $58
million of 4.875% senior secured notes due 2024, $345 million of 3.550% senior secured notes due 2024 and $356 million of
the 5.125% senior secured notes due 2025. We recorded an extinguishment gain of $6 million on the transaction in the first
quarter of 2024.
Accounts Receivable Financing
Accounts Receivable Securitization Program
TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing
facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). In
April 2024, the Receivables Facility was amended to increase the purchase limit from $750 million to $1.0 billion and to add
Energy Harbor LLC, a direct, wholly owned subsidiary of Energy Harbor, as an Originator. The Receivables Facility was
renewed and amended in July 2024, extending the term of the Receivables Facility to July 2025.
In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands,
Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility
(Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables
excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights
(Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn,
is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its
acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related
assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the
performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the
Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings in the consolidated
balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in
the consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra
reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts
advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as
applicable.
As of December 31, 2024, outstanding borrowings under the Receivables Facility totaled $750 million and were
supported by $1.334 billion of RecCo gross receivables. As of December 31, 2023, there were no outstanding borrowings under
the Receivables Facility.
Repurchase Facility
TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that
is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2024, the Repurchase Facility was
renewed until July 2025 while maintaining the facility size of $125 million. The Repurchase Facility is collateralized by a
subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the
Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by
the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer
transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU
Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note
(collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month, unless terminated earlier
on demand by TXU Energy or terminated by Buyer after an event of default.
114

TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note
to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee
the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements
governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the
Receivables Facility.
There were no outstanding borrowings under the Repurchase Facility as of both December 31, 2024 and December 31,
2023.
Forward Repurchase Obligation
In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority
interests from Avenue and Nuveen. Vistra paid Avenue for the purchase of their minority interest in Vistra Vision in full upon
closing and paid Nuveen an initial payment at closing, with the remaining payments to Nuveen to be paid in multiple
installments through December 31, 2026. Vistra Vision Holdings' remaining future payments to Nuveen are guaranteed by
Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. Payments remaining due to
Nuveen are as follows:
December 31,
2024
(in millions)
2025
$
781
2026
669
Thereafter
—
Total scheduled payments under the UPAs
$
1,450
A roll-forward of the noncontrolling interest redemption obligation is as follows (in millions):
Redeemable noncontrolling interest at September 30, 2024
$
3,198
Income attributable to redeemable noncontrolling interest (a)
51
Dividends to redeemable noncontrolling interest holders
(165)
Redeemable noncontrolling interest balance at Closing Date (b)
3,084
Principal payment on Closing Date
(1,749)
Forward Repurchase Obligation at December 31, 2024 (c)
$
1,335
____________
(a) Represents accretion attributable to fixed price redemption obligation.
(b) Reclassified to a financing obligation.
(c) Fair value of the remaining payment obligations to Nuveen discounted at 6%.
Interest Expense and Related Charges
Year Ended December 31,
2024
2023
2022
(in millions)
Interest expense
$
936
$
654
$
591
Unrealized mark-to-market net (gains) losses on interest rate swaps
(53)
36
(250)
Amortization of debt issuance costs, discounts, and premiums
34
26
28
Facility Fee expense
15
8
—
Debt extinguishment gain
(6)
(3)
(1)
Capitalized interest
(77)
(37)
(29)
Other
51
56
29
Total interest expense and related charges
$
900
$
740
$
368
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest
rate swaps discussed in Note 11, was 5.23%, 5.69%, and 4.30% as of December 31, 2024, 2023, and 2022, respectively.
115

10.
LEASES
Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms
for 1 to 42 years. Our leases include options to renew up to 17 years. Certain leases also contain options to terminate the lease.
Lease Cost
The following table presents costs related to lease activities:
Year Ended December 31,
2024
2023
2022
(in millions)
Operating lease cost
$
17
$
12
$
9
Finance lease:
Finance lease right-of-use asset amortization
8
10
9
Interest on lease liabilities
11
11
12
Total finance lease cost
19
21
21
Variable lease cost (a)
29
37
22
Short-term lease cost
56
44
47
Total lease cost
$
121
$
114
$
99
____________
(a) Represents coal stockpile management services, common area maintenance services, and rail car payments based on the
number of rail cars used.
Balance Sheet Information
The following table presents lease related balance sheet information:
December 31,
2024
2023
(in millions)
Lease assets:
Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated
balance sheets)
$
106
$
50
Finance lease right-of-use assets, net of accumulated amortization (reported in property,
plant, and equipment in the consolidated balance sheets)
153
$
160
Total lease right-of-use assets
$
259
$
210
Current lease liabilities (reported in other current liabilities in the consolidated balance
sheets):
Operating lease liabilities
$
13
$
7
Finance lease liabilities
9
9
Total current lease liabilities
22
16
Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the
consolidated balance sheets):
Operating lease liabilities
98
48
Finance lease liabilities
218
227
Total noncurrent lease liabilities
316
275
Total lease liabilities
$
338
$
291
116

Supplemental Cash Flow Information
The following table presents lease related cash flows and other information:
Year Ended December 31,
2024
2023
2022
(in millions)
Non-cash disclosure upon commencement of new lease:
Right-of-use assets obtained in exchange for new operating lease
liabilities
68
3
19
Right-of-use assets obtained in exchange for new finance lease liabilities
—
—
6
Non-cash disclosure upon modification of existing lease:
Modification of operating lease right-of-use assets
1
7
—
Modification of finance lease right-of-use assets
—
(1)
4
Weighted Average Remaining Lease Term
The following table presents weighted average remaining lease term information:
December 31,
2024
2023
Weighted average remaining lease term:
Operating lease
23.8 years
20.1 years
Finance lease
23.7 years
24.0 years
Weighted average discount rate:
Operating lease
7.85%
6.49 %
Finance lease
4.82%
4.81 %
Maturity of Lease Liabilities
The following table presents maturity of lease liabilities:
Operating Lease
Finance Lease
Total Lease
(in millions)
2025
$
19
$
19
$
38
2026
13
14
27
2027
14
13
27
2028
10
13
23
2029
8
13
21
Thereafter
222
331
553
Total lease payments
286
403
689
Less: Imputed interest
(175)
(176)
(351)
Present value of lease liabilities
$
111
$
227
$
338
11.
DERIVATIVES
We utilize derivative instruments, such as options, swaps, futures, and forward contracts to manage our exposure to
commodity price and interest rate volatility. Counterparties to these transactions include energy companies, financial
institutions, electric utilities, independent power producers, fuel oil and natural gas producers, local distribution companies, and
energy marketing companies.
117

Commodity Derivatives
We utilize financial natural gas and financial and physical electricity derivatives to reduce exposure to changes in
electricity prices primarily to hedge future revenues from electricity sales from our generation assets. Financial transmission
rights and congestion revenue rights are derivative instruments we utilize to hedge electricity price differences between
settlement points within regions. Gains and losses associated with these derivatives are reported in the consolidated statements
of operations in operating revenues.
We utilize physical natural gas, coal, emissions, and renewable energy certificate derivatives primarily to hedge future
purchased power costs of our retail operations or fuel costs of our generation assets. Gains and losses associated with these
derivatives are reported in the consolidated statements of operations in fuel, purchased power costs, and delivery fees.
Our retail segment procures power from our generation segments to serve future load obligations. In locations and periods
where our load service activities do not naturally offset existing generation portfolio risks, remaining commodity price exposure
is managed through portfolio hedging activities.
Interest Rate Swaps
Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates
to fixed rates, thereby hedging future interest costs and related cash flows. Gains and losses associated with these derivatives
are reported in the consolidated statements of operations in interest expense and related charges.
As of December 31, 2024, Vistra has entered into the following interest rate swaps:
Notional Amount
Expiration Date
Rate Range (c)
(in millions, except percentages)
Swapped to fixed (a)
$3,000
July 2026
4.64 % - 4.72%
Swapped to variable (a)
$700
July 2026
3.19 % - 3.24%
Swapped to fixed (b)
$2,300
December 2030
4.95 % - 5.51%
____________
(a) The $700 million of pay variable rate and receive fixed rate swaps match the terms of a portion of the $3.0 billion pay
fixed rate and receive variable rate swaps. These matched swaps will settle over time and effectively offset the hedged
position. These offsetting swaps expiring in July 2026 hedge our exposure on $2.3 billion of variable rate debt through
July 2026.
(b) Effective from July 2026 through December 2030.
(c) The rate ranges reflect the fixed leg of each swap at a Term SOFR rate plus an interest margin of 1.75%.
In November 2024, Vistra entered into $675 million notional amount of interest rate swaps effective July 31, 2026 and
expiring on December 31, 2030. These swaps, along with $1.625 billion notional amount of interest rate swaps with similar
terms entered into in 2023, will hedge our exposure on $2.3 billion of floating rate debt from August 2026 through December
2030.
118

Effect of Derivative Instruments in the Consolidated Balance Sheets
We maintain standardized master netting agreements with certain counterparties that allow for the right to offset accounts
payable, accounts receivable and cash collateral paid in order to reduce credit exposure. The following tables reconcile our
gross derivative assets and liabilities as reported in the consolidated balance sheets to the net value on a contract basis, after
taking into consideration netting arrangements with counterparties and cash collateral recorded.
December 31, 2024
Derivative Contract Assets
Derivative Contract Liabilities
Commodity
Contracts
Interest Rate
Swaps
Commodity
Contracts
Interest Rate
Swaps
Total
(in millions)
Current assets
$
2,551
$
34
$
2
$
—
$
2,587
Noncurrent assets
677
62
1
—
740
Current liabilities
—
—
(3,333)
(18)
(3,351)
Noncurrent liabilities
(2)
—
(1,356)
(9)
(1,367)
Net assets (liabilities)
$
3,226
$
96
$
(4,686) $
(27) $
(1,391)
Offsetting instruments (a)
$
(2,532) $
(28) $
2,532
$
28
—
Financial collateral (received) pledged (b) $
(50) $
—
$
233
$
—
183
Net amounts
$
644
$
68
$
(1,921) $
1
$
(1,208)
December 31, 2023
Derivative Contract Assets
Derivative Contract Liabilities
Commodity
Contracts
Interest Rate
Swaps
Commodity
Contracts
Interest Rate
Swaps
Total
(in millions)
Current assets
$
3,585
$
53
$
7
$
—
$
3,645
Noncurrent assets
565
11
1
—
577
Current liabilities
(1)
—
(5,233)
(24)
(5,258)
Noncurrent liabilities
(5)
—
(1,659)
(24)
(1,688)
Net assets (liabilities)
$
4,144
$
64
$
(6,884) $
(48) $
(2,724)
Offsetting instruments (a)
$
(3,519) $
(28) $
3,519
$
28
—
Financial collateral (received) pledged (b) $
(26) $
—
$
970
$
—
944
Net amounts
$
599
$
36
$
(2,395) $
(20) $
(1,780)
____________
(a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin
requirements, and, to a lesser extent, initial margin requirements.
119

Effect of Derivative Instruments in the Consolidated Statements of Operations
The following table summarizes the location and amount of unrealized gains and losses from our derivative instruments
recorded in the consolidated statements of operations for the periods presented.
Year Ended December 31,
Derivative (consolidated statements of operations presentation)
2024
2023
2022
(in millions)
Reversals of previously recognized unrealized (gain) loss on derivative
instruments:
Commodity contracts unrealized (gain) loss in operating revenues (a)
$
1,140
$
1,472
$
1,940
Commodity contracts unrealized (gain) loss in fuel and purchased power
expense (a)
73
171
(722)
Interest rate swaps unrealized (gain) loss in interest expense and related
charges
(41)
(78)
16
Total reversals of previously recognized unrealized (gain) loss on
derivative instruments
$
1,172
$
1,565
$
1,234
Unrealized net gains (losses) from changes in fair value on derivative
instruments:
Commodity contracts unrealized gain (loss) in operating revenues
$
(127) $
(758) $
(4,103)
Commodity contracts unrealized gain (loss) in fuel and purchased power
expense
69
(395)
375
Interest rate swaps unrealized gain (loss) in interest expense and related
charges
94
42
234
Total unrealized net gains (losses) from changes in fair value on
derivative instruments
$
36
$
(1,111) $
(3,494)
Net gain (loss) on derivative instruments
$
1,208
$
454
$
(2,260)
____________
(a)
Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions
entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives
which did not financially settle but realized at the contract's notional and price. The realized effects of these items are
included in operating revenues and fuel and purchased power expense.
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes by commodity, excluding our NPNS
derivatives that are not recorded at fair value:
December 31, 2024
December 31, 2023
Derivative type
Notional Volume
Unit of Measure
Natural gas
4,568
5,335
Million MMBtu
Electricity
796,982
800,001
GWh
Financial transmission rights / Congestion revenue rights
248,742
250,895
GWh
Coal
27
35
Million U.S. tons
Fuel oil
2
3
Million gallons
Emissions
28
24
Million U.S. tons
Renewable energy certificates
31
29
Million certificates
Interest rate swaps – variable/fixed
$
5,300
$
5,225
Million U.S. dollars
Interest rate swaps - fixed/variable
$
700
$
1,300
Million U.S. dollars
120

Credit Risk-Related Contingent Features of Derivatives
Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity
requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these
agreements may require the posting of additional collateral if our credit rating is downgraded by one or more credit rating
agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure
under other financing arrangements related to payment terms or other covenants.
The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are
not fully collateralized:
December 31,
2024
2023
(in millions)
Fair value of derivative contract liabilities (a)
$
(1,587) $
(1,890)
Offsetting fair value under netting arrangements (b)
724
692
Cash collateral and letters of credit
471
854
Liquidity exposure
$
(392) $
(344)
____________
(a)
Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if
features are triggered, including provisions that generally provide the right to request additional collateral (material
adverse change, performance assurance and other clauses).
(b)
Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master
netting arrangements.
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. As of December 31, 2024, total
credit risk exposure to all counterparties related to derivative contracts totaled $3.772 billion (including associated accounts
receivable). The net exposure to those counterparties totaled $776 million as of December 31, 2024 after taking into effect
netting arrangements, setoff provisions and collateral, with the largest net exposure from any single counterparty totaling $262
million. As of December 31, 2024, the credit risk exposure to the banking and financial sector represented 75% of the total
credit risk exposure and 26% of the net exposure.
This concentration of credit risk increases the risk that a default by any of our counterparties could have a material effect
on our financial condition, results of operations and liquidity. We maintain credit risk policies with regard to our counterparties
to minimize overall credit risk. These policies authorize specific risk mitigation procedures including, but not limited to, (i)
requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our
counterparties that allow for netting of positive and negative exposures, and (iii) that detail credit enhancements (such as parent
guarantees, letters of credit, surety bonds, liens on assets and margin deposits) are required in the event of a material downgrade
in their credit rating.
12.
FAIR VALUE MEASUREMENTS
Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are
characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable
inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market
assumptions. We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy as
defined by GAAP:
•
Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the
measurement date.
121

•
Level 2 valuations use over-the-counter broker quotes, quoted prices for similar assets or liabilities that are
corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield
curves observable at commonly quoted intervals.
•
Level 3 valuations use unobservable inputs for the asset or liability, typically reflecting our estimate of assumptions
that market participants would use in pricing the asset or liability. The fair value is therefore determined using model-
based techniques, including discounted cash flow models.
The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on
the lowest level input that is significant to the measurement.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet
dates shown below:
December 31, 2024
December 31, 2023
Level
1
Level
2
Level
3 (a)
Reclass
(a)
Total
Level
1
Level
2
Level
3 (a)
Reclass
(a)
Total
(in millions)
Assets:
Commodity contracts (b)
$1,923
$
462
$
841
$
5
$ 3,231
$2,886
$
628
$
630
$
14
$ 4,158
Interest rate swaps (b)
—
96
—
—
96
—
64
—
—
64
NDTs – equity securities
(c)(d)
1,560
—
—
—
1,560
638
—
—
—
638
NDTs – debt securities
(c)(e)
83
1,976
—
—
2,059
—
734
—
—
734
Sub-total
$3,566
$2,534
$
841
$
5
6,946
$3,524
$1,426
$
630
$
14
5,594
Assets measured at net asset
value (f):
NDTs – equity securities
(c)(d)(f)
821
579
Total assets
$ 7,767
$ 6,173
Liabilities:
Commodity contracts (b)
$2,118
$
975
$1,593
$
5
$ 4,691
$3,815
$1,395
$1,674
$
14
$ 6,898
Interest rate swaps (b)
—
27
—
—
27
—
48
—
—
48
Total liabilities
$2,118
$1,002
$1,593
$
5
$ 4,718
$3,815
$1,443
$1,674
$
14
$ 6,946
____________
(a) Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability
position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the
consolidated balance sheets.
(b) See Note 11 for additional information.
(c) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear
generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment
rules established by the NRC and the PUCT. The NDT investments are included in Investments in the consolidated
balance sheets. There were no significant concentrations of credit risk from an individual counterparty or groups of
counterparties in our NDT portfolio as of December 31, 2024.
(d) The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P
500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments.
(e) The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt
securities are weighted with government and investment grade corporate bonds. Other investable debt securities include,
but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market
bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 3.99% and
3.19% as of December 31, 2024 and 2023, respectively, and an average maturity of 7 years and 11 years as of December
31, 2024 and 2023, respectively. NDT debt securities held as of December 31, 2024 mature as follows: $1.045 billion in
one to five years, $599 million in five to 10 years and $415 million after 10 years.
122

(f)
Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair
values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this
table to the amounts presented in the consolidated balance sheets.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant
unobservable inputs used in the valuations as of December 31, 2024 and 2023:
December 31, 2024
Fair Value
Contract Type (a)
Assets
Liabilities
Total, Net
Valuation
Technique
Significant Unobservable Input
Range (b)
Average
(b)
(in millions)
Electricity
purchases and sales
$
606
$ (1,399) $
(793)
Income
Approach
Hourly price curve shape
(c)
$ —
to $ 95
$ 48
MWh
Illiquid delivery periods for
hub power prices (d)
$ 25
to $140
$ 83
MWh
Market Heat Rates (d)
$ 30
to $150
$ 90
MWh
Options
6
(139)
(133)
Option
Pricing
Model
Natural gas to power
correlation (e)
10 % to
100 %
55 %
Power and natural gas
volatility (e)
5 % to
710 %
358 %
Financial
transmission rights/
Congestion
revenue rights
190
(25)
165
Market
Approach
(f)
Illiquid price differences
between settlement points
(g)
$(35)
to $ 20
$ (8)
MWh
Natural gas
29
(30)
(1)
Income
Approach
Natural gas basis (h)
$ —
to $ 10
$
5
MMBtu
Illiquid delivery periods (i)
$ —
to $
5
$
2
MMBtu
Other (j)
10
—
10
Total
$
841
$ (1,593) $
(752)
123

December 31, 2023
Fair Value
Contract Type (a)
Assets
Liabilities
Total, Net
Valuation
Technique
Significant Unobservable Input
Range (b)
Average
(b)
(in millions)
Electricity
purchases and sales
$
449
$ (1,273) $
(824)
Income
Approach
Hourly price curve shape
(c)
$ —
to $ 85
$ 44
MWh
Illiquid delivery periods for
hub power prices and Heat
Rates (d)
$ 30
to $110
$ 71
MWh
Options
1
(237)
(236)
Option
Pricing
Model
Natural gas to power
correlation (e)
10 % to
100 %
55 %
Power and natural gas
volatility (e)
10 % to
870 %
441 %
Financial
transmission rights/
Congestion
revenue rights
157
(34)
123
Market
Approach
(f)
Illiquid price differences
between settlement points
(g)
$(85)
to $ 25
$ (30)
MWh
Natural gas
9
(112)
(103)
Income
Approach
Natural gas basis (h)
$ —
to $ 15
$
6
MMBtu
Illiquid delivery periods (i)
$ —
to $
5
$
4
MMBtu
Other (j)
14
(18)
(4)
Total
$
630
$ (1,674) $ (1,044)
____________
(a) Electricity purchase and sales contracts include (i) power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO,
MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii)
Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are
referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE,
NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts.
(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The
average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional
amount.
(c) Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone
prices.
(d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability.
(e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM.
(f)
While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the
valuation liquid.
(g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices.
(i)
Primarily based on the historical forward natural gas fixed prices.
(j)
Other includes contracts for coal and environmental allowances.
124

The following table presents the changes in fair value of the Level 3 assets and liabilities:
Year Ended December 31,
2024
2023
2022
(in millions)
Net liability balance at beginning of period
$
(1,044) $
(1,219) $
(360)
Total unrealized valuation gains (losses)
(175)
(765)
(1,382)
Purchases, issuances and settlements (a):
Purchases
266
222
185
Issuances
(26)
(30)
(62)
Settlements
137
136
345
Transfers into Level 3 (b)
(15)
(48)
(30)
Transfers out of Level 3 (b)
118
660
85
Net liabilities assumed in connection with the Energy Harbor Merger
(13)
—
—
Net change
292
175
(859)
Net liability balance at end of period
$
(752) $
(1,044) $
(1,219)
Unrealized valuation (losses) relating to instruments held at end of period
$
(416) $
(676) $
(977)
____________
(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and
issuances reflect option premiums paid or received, including CRRs and FTRs.
(b) Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods
presented are in and out of Level 2. For the year ended December 31, 2024, transfers into Level 3 primarily consist of
power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist
of power and natural gas derivatives where forward pricing inputs have become observable. For the year ended December
31, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become
unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs
have become observable. For the year ended December 31, 2022, transfers into Level 3 primarily consist of power and
coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of
power, natural gas, and coal derivatives where forward pricing inputs have become observable.
Assets and Liabilities Recorded on a Non-Recurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not
measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and
liabilities can include inventories, assets acquired and liabilities assumed in business combinations, goodwill and other long-
lived assets that are written down to fair value when they are determined to be impaired or held for sale.
The Energy Harbor Merger was accounted for under the acquisition method which requires all assets acquired and
liabilities assumed in the acquisition be recorded at fair value at the acquisition date. See Note 2 for additional information.
Fair Value of Debt
December 31, 2024
December 31, 2023
Instrument
Fair Value
Hierarchy
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
(in millions)
Long-term debt under the Vistra Operations
Credit Facilities
Level 2
$
2,435
$
2,478
$
2,456
$
2,500
BCOP Credit Facilities Tax Credit Bridge
Loan
Level 3
344
367
—
—
Vistra Zero Term Loan B Facility
Level 2
685
697
—
—
Vistra Operations Senior Notes
Level 2
12,366
12,428
11,881
11,752
Energy Harbor Revenue Bonds
Level 2
414
431
—
—
Equipment Financing Agreements
Level 3
54
53
65
62
Forward Repurchase Obligation
Level 3
1,335
1,335
—
—
125

We determine fair value in accordance with accounting standards. We obtain security pricing from an independent party
who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated
through subscription services, such as Bloomberg.
13.
ASSET RETIREMENT OBLIGATIONS
Our asset retirement obligations (ARO) primarily relate to nuclear generation plant decommissioning, land reclamation
related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. AROs are based on
legal obligations associated with enacted law, regulatory, or contractual retirement requirements for which decommissioning
timing and cost estimates are reasonably estimable.
The following table summarizes the changes to our current and noncurrent ARO liabilities for the years ended December
31, 2024 and 2023:
Nuclear Plant
Decommissioning
Land Reclamation,
Coal Ash and Other
Total
(in millions)
Liability at December 31, 2022
$
1,688
$
749
$
2,437
Additions:
Accretion (a)
54
34
88
Adjustment for change in estimates (b)
—
94
94
Reductions:
Payments
—
(81)
(81)
Liability at December 31, 2023
1,742
796
2,538
Additions:
Accretion (a)
130
40
170
Adjustment for change in estimates (b)
—
90
90
Adjustment for obligations assumed through acquisitions
1,368
—
1,368
Reductions:
Payments
—
(88)
(88)
Liability at December 31, 2024
3,240
838
4,078
Less amounts due currently
—
(142)
(142)
Noncurrent liability at December 31, 2024
$
3,240
$
696
$
3,936
____________
(a) For the year ended December 31, 2024, nuclear plant decommissioning accretion includes $74 million of accretion
expense recognized in operating costs in the consolidated statements of operations and $56 million reflected as a change
in regulatory liability in the consolidated balance sheets. For the year ended December 31, 2023, nuclear plant
decommissioning accretion reflected as a change in regulatory liability in the consolidated balance sheets.
(b) Includes non-cash additions to asset retirement costs included in property, plant, and equipment of $52 million and
$67 million for the years ended December 31, 2024 and 2023, respectively.
For the next five years, Vistra is projected to spend approximately $546 million (on a nominal basis) to achieve its mining
reclamation and other coal ash remediation objectives.
Nuclear Decommissioning AROs
AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the facilities acquired
from Energy Harbor which include the Beaver Valley, Perry and Davis-Besse plants in PJM (the PJM nuclear facilities). To
estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis,
considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates,
probabilistic cash flow models, and discount rates.
126

As of December 31, 2024, the carrying value of our ARO related to our Comanche Peak nuclear generation facility
decommissioning totaled $1.797 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT
of $2.249 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $452
million recorded to the consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in
the NDT after decommissioning our Comanche Peak plant would be refunded to Oncor.
The carrying value of our ARO for our PJM nuclear facilities was recorded at fair value on the Merger Date. ARO
accretion expense attributable to the PJM nuclear facilities is reflected in operating costs in the consolidated statements of
operations. ARO estimates for the PJM nuclear facilities will be evaluated on an individual unit basis at least every five years
unless triggering events warrant a more frequent review. Any changes in ARO estimates are recorded as an increase or decrease
in ARO liability along with a corresponding change to asset retirement cost asset within property, plant, and equipment in the
consolidated balance sheets; however, if the ARO estimate decreases by more than the remaining ARO asset, the balance of the
change is recorded as a reduction to operating costs in the consolidated statement of operations.
14.
PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS
Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible
employees of its subsidiaries. Oncor is a participant in the Retirement Plan. Effective January 1, 2018, Vistra entered into a
contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split
Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-
regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra. As Vistra accounts for its interests in the
Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension
benefit information presented below. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of
the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan
provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly
contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest
credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of
highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our
policy to fund the Retirement Plan assets only to the extent required under existing federal regulations. Since 2012, the
Retirement Plan has been closed to new participants and the only participants who remain in the Retirement Plan are employees
who were active prior to 2012, including retired collective bargaining unit employees. Accordingly, ongoing expenses
associated with the Retirement plan are immaterial, including expenses associated with pensions plans acquired from Dynegy
and Energy Harbor.
Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain
health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required for
such coverage vary based on a formula depending on the retiree's age and years of service.
Pension and OPEB Costs
The following table summarizes the total benefit costs of our pension and OPEB plans for the years ended December 31,
2024, 2023, and 2022. The individual components of benefit costs, including service cost, interest cost, expected return on
assets and the net amortization of unrecognized amounts from accumulated other comprehensive income were immaterial.
Year Ended December 31,
2024
2023
2022
(in millions)
Pension costs
$
9
$
9
$
2
OPEB costs
5
5
4
Total benefit costs recognized as expense
$
14
$
14
$
6
127

Market-Related Value of Assets Held in Pension Benefit Trusts
We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of
calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period.
Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-
related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and
is decreased for benefit payments and expenses for that year.
Detailed Information Regarding Pension Plans and OPEB Benefits
The following information is based on a December 31, 2024, 2023, and 2022 measurement dates:
Retirement Plan
OPEB Plans
Year Ended December 31,
Year Ended December 31,
2024
2023
2022
2024
2023
2022
Assumptions Used to Determine Benefit Obligations at
Period End:
Discount rate
5.63 %
4.97 %
5.16 %
5.62 %
4.98 %
5.18 %
Expected rate of compensation increase (Vistra Plan)
3.50 %
3.64 %
3.79 %
Expected rate of compensation increase (Dynegy Plan)
4.46 %
Interest crediting rate for cash balance plans
3.75 %
3.50 %
3.00 %
(in millions, except percentages)
Change in Pension and Postretirement Benefit Obligations:
Projected benefit obligation at beginning of period
$
425
$
449
$
108
$
110
Acquisitions
23
—
—
—
Service cost
2
3
1
1
Interest cost
21
21
5
5
Participant contributions
—
—
3
3
Plan amendments
—
1
—
—
Actuarial (gain) loss
(24)
10
(7)
1
Benefits paid
(38)
(59)
(11)
(12)
Projected benefit obligation at end of year
$
409
$
425
$
99
$
108
Accumulated benefit obligation at end of year
$
408
$
422
$
—
$
—
Change in Plan Assets:
Fair value of assets at beginning of period
$
285
$
320
$
12
$
29
Acquisitions
18
—
—
—
Employer contributions
19
—
8
9
Participant contributions
—
—
2
3
Actual gain on assets
1
24
1
2
Transfers
—
—
(2)
(19)
Benefits paid
(38)
(59)
(11)
(12)
Fair value of assets at end of year
$
285
$
285
$
10
$
12
Funded Status:
Projected benefit obligation
$
(409) $
(425)
$
(99) $
(108)
Fair value of assets
285
285
10
12
Funded status at end of year
$
(124) $
(140)
$
(89) $
(96)
Retirement Plan
OPEB Plans
Year Ended December 31,
Year Ended December 31,
2024
2023
2024
2023
128

Amounts Recognized in the Balance Sheet Consist of:
Investments
$
1
$
—
$
2
$
3
Other current liabilities
—
—
(8)
(9)
Other noncurrent liabilities
(125)
(140)
(83)
(90)
Net liability recognized
$
(124) $
(140)
$
(89) $
(96)
Amounts Recognized in Accumulated Other Comprehensive
Income Consist of:
Net actuarial (gain) loss
$
(5) $
4
$
(22) $
(15)
Prior services cost
—
3
1
1
Net actuarial (gain) loss and prior service cost
$
(5) $
7
$
(21) $
(14)
Retirement Plan
OPEB Plans
Year Ended December 31,
Year Ended December 31,
2024
2023
2024
2023
Fair Value Measurement of Pension and OPEB Plan Assets
Retirement Plan
As of December 31, 2024 and 2023, all of the Retirement Plan assets were measured at fair value using the net asset
value per share (or its equivalent) except as noted and consisted of the following:
December 31,
2024
2023
(in millions)
Asset Category:
Cash commingled trusts
$
6
$
4
Equity securities:
Global equities
86
82
Fixed income securities:
Corporate bonds (a)
79
82
Government bonds
42
54
Other (b)
28
18
Real estate
27
28
Hedge funds
17
17
Total assets measured at net asset value
$
285
$
285
___________
(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.
(b) Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade
fixed income.
OPEB Plans
As of December 31, 2024 and 2023, the Vistra OPEB plan assets measured at fair value totaled $10 million and $12
million, respectively. At December 31, 2024 and 2023, assets consisted of $7 million and $9 million, respectively, of comingled
funds valued at net asset value and $3 million and $3 million, respectively, of municipal bond and cash equivalent mutual funds
classified as Level 1.
129

Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan
Assets
The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan
assets.
December 31,
2024
2023
(in millions)
Pension Plans with PBO and ABO in Excess of Plan Assets:
Projected benefit obligations
$
409
$
425
Accumulated benefit obligation
$
408
$
422
Plan assets
$
285
$
285
Retirement Plan Investment Strategy and Asset Allocations
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit
obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held
primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities, and money
market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities.
International equity securities are used to further diversify the equity portfolio and may include investments in both developed
and emerging markets. Real estate, hedge funds, and credit strategies (primarily high yield bonds and emerging market debt)
provide additional portfolio diversification and return potential.
The target asset allocation ranges of pension plan investments by asset category are as follows:
Retirement Plan
Target Allocation Ranges
Asset Category:
Vistra Plan
Dynegy Plan
Energy Harbor Plan
Fixed income securities
50 % - 70%
40 % - 50%
45 % - 55%
Global equity securities
20 % - 28%
28 % - 38%
30 % - 38%
Real estate
6 % - 10%
7 % - 15%
5 % - 10%
Credit strategies
2 % - 6%
4 % - 8%
4 % - 8%
Hedge funds
2 % - 6%
4 % - 8%
1 % - 5%
Retirement Plan Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a
comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies.
The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset
class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the
diversification benefits of investing in multiple asset classes and potential benefits of employing active investment
management.
Retirement Plan
Expected Long-Term Rate of Return
Asset Class:
Vistra Plan
Dynegy Plan
Energy Harbor Plan
Fixed income securities
5.9 %
5.5 %
4.6 %
Global equity securities
7.2 %
7.2 %
7.2 %
Real estate
5.8 %
5.8 %
5.8 %
Credit strategies
7.4 %
7.4 %
7.4 %
Hedge funds
7.3 %
7.3 %
7.3 %
Weighted average
6.3 %
6.3 %
5.8 %
130

Benefit Plan Assumed Health Care Cost Trend Rates
The following tables provide information regarding the assumed health care cost trend rates.
December 31,
2024
2023
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year
7.00 %
7.00 %
Rate to which the cost trend is expected to decline (the ultimate trend rate)
4.50 %
4.50 %
Year that the rate reaches the ultimate trend rate
2034
2033
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year (Vistra Plan)
15.70 %
12.90 %
Health care cost trend rate assumed for next year (Split-Participant Plan)
13.80 %
12.30 %
Rate to which the cost trend is expected to decline (the ultimate trend rate)
4.50 %
4.50 %
Year that the rate reaches the ultimate trend rate
2034
2033
Significant Concentrations of Risk
The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize
return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing
capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be
diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There
are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio
weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond
yields and at December 31, 2024 consisted of 490 corporate bonds with an average rating of AA using Moody's, S&P and Fitch
ratings.
Contributions
Contributions to the Retirement Plan for the years ended December 31, 2024, 2023, and 2022 totaled $19 million, zero,
and zero, respectively, and contributions in 2025 are expected to total $25 million. OPEB plan funding for each of the years
ended December 31, 2024, 2023, and 2022 totaled $8 million, $9 million, and $9 million, respectively, and funding in 2025 is
expected to total $8 million.
Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
2025
2026
2027
2028
2029
2030-2034
(in millions)
Pension benefits
$
33
$
34
$
43
$
32
$
32
$
151
OPEB
$
9
$
9
$
9
$
8
$
8
$
36
131

Qualified Savings Plans
Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined
contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the
terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly
compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75%
of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such
threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in
an amount equal to 100% (75% for employees covered under the traditional formula in the Retirement Plan) of the first 6% of
employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the
plan's investment options.
Aggregate employer contributions to the qualified savings plans totaled $46 million, $33 million, and $33 million for the
years ended December 31, 2024, 2023, and 2022, respectively.
15.
COMMITMENTS AND CONTINGENCIES
Contractual Commitments
As of December 31, 2024, we had minimum contractual commitments under long-term service and maintenance
contracts, energy-related contracts and other agreements as follows:
Long-Term Service
and Maintenance
Contracts (a)
Coal transportation
agreements
Pipeline transportation
and storage reservation
fees
Water
Contracts
(in millions)
2025
$
227
$
59
$
187
$
9
2026
206
26
200
9
2027
207
26
209
9
2028
265
—
228
9
2029
259
—
234
9
Thereafter
1,916
—
115
37
Total
$
3,080
$
111
$
1,173
$
82
____________
(a) Long-term service and maintenance contracts reflect expected expenditures as these contracts do not include minimum
spending requirements, but can only be terminated based on events outside the control of the Company.
In addition to the commitments detailed above, we have nuclear fuel contracts with early termination penalties. As of
December 31, 2024, termination costs of $116 million would be incurred if we terminated those contracts.
Expenditures under our coal purchase and coal transportation agreements totaled $744 million, $936 million, and $995
million for the years ended December 31, 2024, 2023, and 2022, respectively.
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment
under certain conditions.
Letters of Credit
As of December 31, 2024, we had outstanding letters of credit totaling $2.935 billion as follows:
•
$2.560 billion to support commodity risk management and collateral requirements in the normal course of business,
including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;
•
$248 million to support battery and solar development projects;
•
$25 million to support executory contracts and insurance agreements;
•
$86 million to support our REP financial requirements with the PUCT; and
•
$16 million for other credit support requirements.
132

Surety Bonds
As of December 31, 2024, we had outstanding surety bonds totaling $1.087 billion to support performance under various
contracts and legal obligations in the normal course of business.
Litigation and Regulatory Proceedings
Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we
have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to
participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when
information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated.
As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as
incurred. Management has assessed each of the following legal matters based on current information and made a judgment
concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the
probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the
scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of
operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and
estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties
and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are
different from our currently recorded reserves and that such differences could be material.
Litigation
Natural Gas Index Pricing Litigation — We, through our subsidiaries, and another company remain named as defendants
in one consolidated putative class action lawsuit pending in federal court in Wisconsin claiming damages resulting from alleged
price manipulation through false reporting of natural gas prices to various index publications, wash trading, and churn trading
from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas
prices during the relevant time period and seek damages under the respective state antitrust statutes. In April 2023, the U.S.
Court of Appeals for the Seventh Circuit (Seventh Circuit Court) heard oral argument on an interlocutory appeal challenging
the district court's order certifying a class.
Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney
General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius in July 2019. The complaint filed
in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged
customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to
dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted
by the Illinois Attorney General that were outside of the 5-year statute of limitations period, which now limits the period during
which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged
in its complaint.
Ohio House Bill 6 ("HB6") — In July 2019, Ohio adopted a law referred to as HB6, which, among other things, provided
subsidies for two nuclear power plants which we acquired in March 2024 upon the closing of our merger with Energy Harbor.
We had opposed enactment of that subsidy legislation at the time, and the nuclear subsidies were repealed in 2021 prior to any
subsidies being distributed. The U.S. Attorney's Office conducted an investigation into the activities related to the passage of
HB6, and Energy Harbor received a grand jury subpoena in July 2020 requiring production of certain information related to that
investigation. Energy Harbor completed its responses to that subpoena by December 2021. In August 2020, the Ohio Attorney
General filed a civil Racketeer Influenced and Corrupt Organizations Act (RICO) complaint against FirstEnergy Corp. and
various Energy Harbor companies related to passage of HB6 (State of Ohio ex rel. Dave Yost, Ohio Attorney General v.
FirstEnergy Corp., et al., Franklin County, Ohio Common Pleas Court Case No. 20CV006281 and State of Ohio ex rel. Dave
Yost, Ohio Attorney General v. Energy Harbor Corp., et al., Franklin County, Ohio Common Pleas Court Case No.
20CV007386). Motions to dismiss those cases remain pending and the case is currently stayed.
133

Winter Storm Uri Legal Proceedings
Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory
bodies, including ERCOT, the ERCOT Independent Market Monitor, and the Texas Attorney General initiated investigations or
issued requests for information of various parties related to the significant load shed event that occurred during the event as well
as operational challenges for generators arising from the event, including performance and fuel and supply issues. We
responded to all those investigatory requests. In addition, a large number of personal injury and wrongful death lawsuits related
to Winter Storm Uri have been, and continue to be, filed in various Texas state courts against us and numerous generators,
transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants requested that
all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL)
pretrial judge. In June 2021, the MDL panel granted the request to consolidate all these cases into an MDL for pretrial
proceedings. Additional personal injury cases that have been, and continue to be, filed on behalf of additional plaintiffs have
been consolidated with the MDL proceedings. In addition, in January 2022, an insurance subrogation lawsuit was filed in
Austin state court by over one hundred insurance companies against ERCOT, Vistra and several other defendants. The lawsuit
seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter
Storm Uri, and that case has also now been consolidated with the MDL proceedings. In the summer of 2022, various defendant
groups filed motions to dismiss five so-called bellwether cases, and the MDL court heard oral argument on those motions in
October 2022. In January 2023, the MDL court ruled on the various motions to dismiss and denied the motions to dismiss of the
generator defendants and the transmission distribution utilities defendants, but granted the motions of some of the other
defendant groups, including the retail electric providers and ERCOT. In February 2023, the generator defendants filed a
mandamus petition with the First Court of Appeals in Houston, Texas (First Court of Appeals) to review the MDL court's denial
of the motion to dismiss. In December 2023, the First Court of Appeals in a unanimous decision granted our mandamus petition
and instructed the MDL court to grant the motions to dismiss in full filed by the generator defendants. In January 2024, the
plaintiffs filed a request with the full Court of Appeals to review that panel ruling, which was denied in November 2024. The
plaintiffs have petitioned the Texas Supreme Court to review that decision. We believe we have strong defenses to these
lawsuits and intend to defend against these cases vigorously if they continue.
Moss Landing 300 Battery Fire
On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power
Plant site. We are working closely with all local, state, and federal regulatory authorities on the response, and we are
investigating the cause of the fire. We are also responding to various regulatory bodies, including the CPUC, the EPA, and
others investigating the incident. Finally, two lawsuits have been filed in California state court against Vistra, LG, and others,
arising from the event.
Unleashing American Energy Executive Order
In January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American
Energy (the Order) that ordered that all federal agencies are to review all existing regulations, orders, and other actions for
consistency with the policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies. The Order
requires the EPA to review the GHG, CSAPR, Legacy CCR and ELG rules discussed below. Additionally, the Order states the
U.S. Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews.
134

Greenhouse Gas Emissions (GHG)
In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the
Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final
GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-,
oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and
sequestration/storage (CCS) and natural gas co-firing. Starting in 2030, the rule would begin to require more CO2 emissions
control at certain existing fossil fuel-fired steam generating units, with more stringent standards beginning in 2032 for coal-fired
units that plan to operate for a longer period of time. For new natural gas combustion turbines that operate more frequently, the
rule would phase in increasingly stringent CO2 requirements over time. Under the rule, states would be required to submit plans
to the EPA within 24 months of the rule's publication in the Federal Register that provide for the establishment,
implementation, and enforcement of standards of performance for existing sources. These state plans must generally establish
standards that are at least as stringent as the EPA's emission guidelines. Under the rule, existing coal-fired steam generation
units that will operate on or after January 1, 2039 must start complying with their standards of performance (based on
application of CCS with 90 percent capture) by January 1, 2032. Units that are permanently retiring before January 1, 2039, but
after December 31, 2031, must start complying with their standards of performance (based on co-firing with 40 percent natural
gas on a heat input basis) beginning on January 1, 2030. Units permanently retiring by January 1, 2032 are exempt from the
rule. Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only
coal units that are subject to this rule. Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also
regulated under this rule. None of our existing large or small combustion turbines are subject to this rule. The rule also regulates
any new gas units. For new combustion turbine units, the rule establishes three different categories depending on how
intensively those units are operated, with immediate compliance obligations for all three categories but more stringent standards
beginning in 2032 only for the category of units operating the most intensively. Following finalization of the rule in May 2024,
17 petitions for review from various states, industry groups, and companies were filed in the D.C. Circuit Court along with
multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. In July 2024, the D.C.
Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S.
Supreme Court to stay the rule which was denied in October 2024. Oral argument on the merits of the legal challenges to the
rule was held in December 2024 before the D.C. Circuit Court. In February 2025, the D.C. Circuit granted the unopposed
motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while
the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.
Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan
In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to
lower the 8-hour standard for ozone emissions during ozone season (May to September). As required under the CAA, in
October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from
Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect
to the revised ozone NAAQS. In February 2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain
trade groups, and others challenged that disapproval in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). In
March 2023, those same parties filed motions to stay the EPA's SIP disapproval in the Fifth Circuit Court and the EPA moved
to transfer our challenges to the D.C. Circuit Court or have those challenges dismissed.
In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to
address the 2015 ozone NAAQS. We, along with many other companies, trade groups, states, and ISOs, including ERCOT,
PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of
the proposal, particularly those that may result in challenges to electric reliability under certain conditions. In March 2023, the
EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP). The FIP applied to 22 states beginning with the
2023 ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey,
New York, Ohio, Pennsylvania, Texas, Virginia, and West Virginia. Texas would be moved into the revised (and more
restrictive) Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets
for 2023 that the EPA says are achievable through existing controls installed at power plants. Allowances will be limited under
the program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of
coal-fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic
reduction systems such as our Martin Lake power plant.
135

In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision
on the merits and denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. As a result of the stay, we do not
believe the EPA has authority to implement the GNP FIP as to Texas sources pending the resolution of the merits, meaning that
Texas will remain in Group 2 and not be subject to any requirements under the GNP FIP at least until the Fifth Circuit Court
rules on the merits. Oral argument was heard in December 2023 before the Fifth Circuit Court. In June 2023, the EPA published
the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the
Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the GNP FIP in
the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the
motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the GNP
FIP as to Texas is stayed. In February 2025, the Department of Justice filed a motion on behalf of the EPA in the Fifth Circuit
Court, seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it
wishes to proceed. In February 2025, the State of Texas filed a response opposing the requested abatement, which we joined. In
July 2023, the Fifth Circuit Court ruled that the GNP FIP challenge would be held in abeyance pending the resolution of the
litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay. In a related
action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S. Supreme Court granted a stay of the
GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a
result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP. In February 2025, the
D.C. Circuit Court denied a motion filed by the Department of Justice on behalf of the EPA, seeking to hold the litigation in
abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to
proceed.
Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas
In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule
serving as a partial approval of Texas' 2009 SIP and a partial FIP. For SO2, the rule established an intrastate Texas emission
allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The
program includes 39 generation units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2,
and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. For NOX, the rule adopted the
CSAPR's ozone program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity
generation units are subject to BART for particulate matter. In August 2020, the EPA issued a final rule affirming the prior
BART final rule but also included additional revisions that were proposed in November 2019. Challenges to both the 2017 rule
and the 2020 rules have been consolidated in the D.C. Circuit Court, where we have intervened in support of the EPA. We are
in compliance with the rule, and the retirements of our Monticello, Big Brown, and Sandow 4 plants have enhanced our ability
to comply. The EPA is in the process of reconsidering the BART rule, and the challenges in the D.C. Circuit Court have been
held in abeyance pending the EPA's final action on reconsideration. In May 2023, a proposed BART rule was published in the
Federal Register that would withdraw the trading program provisions of the prior rule and would establish SO2 limits on six
facilities in Texas, including Martin Lake and Coleto Creek. Under the current proposal, compliance would be required within 3
years for Martin Lake and 5 years for Coleto Creek. Due to the announced shutdown for Coleto Creek, we do not anticipate any
impacts at that facility, and we are evaluating potential compliance options at Martin Lake should this proposal become final.
We submitted comments to the EPA on this proposal in August 2023.
136

SO2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation
plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment
plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in
the Fifth Circuit Court. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized,
would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable. In May
2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants,
redesignating those areas as attainment based on monitoring data supporting an attainment designation. In June 2021, the EPA
published two notices; one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice
denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations. We, along with
the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court,
and this case was argued before the Fifth Circuit Court in July 2022. In September 2021, the TCEQ considered a proposal for
its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO2 emissions from the plant. The
proposed agreed order associated with the SIP proposal reduced emission limits as of January 2022. Emission reductions
required are those necessary to demonstrate attainment with the NAAQS. The TCEQ's SIP action was finalized in February
2022 and has been submitted to the EPA for review and approval. In January 2024, in a split decision, the Fifth Circuit Court
denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO2 for the
area around Martin Lake. As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains
in place. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January
2024, which remains pending before the full Fifth Circuit Court. In August 2024, the EPA proposed a Finding of Failure to
attain the SO2 standard for Rusk and Panola Counties, a partial approval and partial disapproval of the Texas SIP and a
proposed federal plan for the area. In December 2024, the EPA finalized the Finding of Failure to attain the standard and stated
that it would take final action of the SIP partial approval and disapproval in a future action. In February 2025, we, along with
the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court.
Particulate Matter
In February 2024, the EPA issued a rule addressing the annual health-based national ambient air quality standards for fine
particulate matter (or PM2.5). In general, the rule lowers the level of the annual PM2.5 standard from 12.0 micrograms per
cubic meter (µg/m3) to 9.0 µg/m3. The effective date of the rule is 60 days from publication in the Federal Register, and the
earliest attainment date for areas exceeding the new standard is 2032. Based on 2021-2023 design value associated with the
rule, we have just four plants (Calumet (Illinois), Dicks Creek and Miami Fort (Ohio), and Lake Hubbard (Texas)) operating in
areas where the air quality monitoring data are currently exceeding the new PM2.5 standard. We have previously announced
that our Miami Fort generation facility will close by the end of 2027. States will have to develop a plan (by late 2027 at the
earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those
sites. However, before the state begins this planning process, the designation process will occur within two years from the
issuance of the final rule. The states develop recommendations about the boundaries of the nonattainment counties and the EPA
must finalize the designations including the boundaries of each nonattainment area.
137

Effluent Limitation Guidelines (ELGs)
In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent
standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom
ash, and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were
consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and
administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded
portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA published a final
rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December
2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts
facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020,
environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in
support of the EPA in December 2020. Notifications were made to Texas, Illinois, and Ohio state agencies on the retirement
exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In May 2024, the EPA published the final
ELG rule revisions, which contain new requirements for legacy wastewater and combustion residual leachate. The final rule
also leaves in place the subcategory for facilities that permanently cease coal combustion by 2028. We are reviewing the rule
for impact but believe it will require additional treatment costs for legacy wastewaters during pond closure activities and
combustion residual leachate. At this time, we don't expect the impact of these additional treatment costs to be material. A
number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals for the Eighth Circuit.
We are not a party to that litigation. In February 2025, the Department of Justice on behalf of the EPA filed an unopposed
motion seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it
wishes to proceed.
Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications
In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR
rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a
deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The 2020 final rule
allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and
either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the
size of the impoundment at issue).
Prior to the November 2020 deadline to seek extensions, we submitted applications to the EPA requesting compliance
extensions under both conversion and retirement scenarios. In January 2022, the EPA determined that our conversion and
retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications.
Legacy CCR Rulemaking
In May 2024, the EPA published a final rule that expands coverage of groundwater monitoring and closure requirements
to the following two new categories of units: (a) legacy CCR surface impoundments which are CCR surface impoundments that
no longer receive CCR but contained both CCR and liquids on or after October 19, 2015 and (b) "CCR management
units" (CCRMUs) which generally could encompass noncontainerized ash deposits greater than one ton and impoundments and
landfills that closed prior to October 19, 2015. As part of the rule, the EPA identified numerous CCR management units across
the country, including ten of our potential units. The Vermilion ash ponds discussed below are the only unit which we believe
qualify as a legacy CCR surface impoundment and given our closure plan for that site we do not believe the rule will have any
impact on that site. CCRMUs with 1,000 or more tons of CCR must comply with the CCR's groundwater monitoring, corrective
action, closure and post-closure requirements. For CCRMUs, complete facility evaluation reports are due within 33 months
after publication of the rule, initial groundwater reports are due January 31, 2029, and the deadline to initiate closure, if needed,
will start in 2029. Closure of the CCRMUs may also be deferred beyond those dates depending on certain factors, including
where the CCRMU is located beneath critical infrastructure. In addition, certain closures may not be required when closure was
previously approved under a state program. Because facility evaluation reports will determine our unit-specific compliance
obligations, we cannot determine them at this time. In August 2024, we, along with USWAG, several other generating
companies, and 17 states, including Texas, filed a challenge to the rule in the D.C. Circuit Court. In February 2025, the D.C.
Circuit Court granted an unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in
abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to
proceed.
138

MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of
groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices
remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east,
and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility.
At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned
D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR
surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in
2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion
surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing
options. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface
impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the
Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a
complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation
notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic
river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim
consent order, DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation
(discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment
closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if
necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the
impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency
Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms
above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and
submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash.
These proposed closure costs are reflected in the ARO in the consolidated balance sheets (see Note 13 for additional
information).
In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen
facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal
CCR rule.
In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements
for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of
guidelines, rules, and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became
effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA
for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal
at any site. In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over
certain provisions of the final rule. In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry
petitions. We do not anticipate any impacts from this decision. In October 2021, we filed operating permit applications for 18
impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in
January 2022 and five of our sites in July 2022. One additional closure construction application was filed for our Baldwin
facility in August 2023.
For all of the above CCR matters, if certain corrective action measures, including groundwater treatment or removal of
ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on
our financial condition, results of operations, and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not
require removal. However, the rule required us to undertake further site-specific evaluations required by each program. We will
not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required
under the Illinois rule until permit applications have been approved by the IEPA and as such, an estimate of such costs cannot
be made. The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the
costs of closure methods that our operations and environmental services teams determined were appropriate based on the
existing closure requirements at the time we recorded those ARO liabilities, and is reasonably possible for those to increase
once the IEPA determines final closure requirements. Once the IEPA acts on our permit applications, we will reassess the
decommissioning costs and adjust our ARO liabilities accordingly.
139

MISO 2015-2016 Planning Resource Auction
In May 2015, three complaints were filed at the FERC regarding the Zone 4 results for the 2015-2016 planning resource
auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc.,
the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as
unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure
going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4
constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was
responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding
occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by
the Complainants. We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff
in connection with the PRA and disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at
the FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this
complaint with respect to Dynegy's conduct alleged in the complaint.
In October 2015, the FERC issued an order of nonpublic, formal investigation (the investigation) into whether market
manipulation or other potential violations of the FERC orders, rules and regulations occurred before or during the PRA.
In December 2015, the FERC issued an order on the complaints requiring a number of prospective changes to the MISO
tariff provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the
Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future
order.
In July 2019, the FERC issued an order denying the remaining issues raised by the complaints and noted that the
investigation into Dynegy was closed. The FERC found that Dynegy's conduct did not constitute market manipulation and the
results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff. A request for
rehearing was denied by the FERC in March 2020. The order was appealed by Public Citizen, Inc. to the D.C. Circuit Court in
May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020. In August 2021, the
D.C. Circuit Court issued a ruling denying Public Citizen, Inc.'s arguments that the FERC failed to meet its obligation to ensure
just and reasonable rates because it did not review the prices resulting from the auction before those prices went into effect and
that the FERC was arbitrary and capricious in failing to adequately explain its decision to close its investigation into whether
Dynegy engaged in market manipulation. The D.C. Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part
finding that the FERC's decision that the auction results were just and reasonable solely because the auction process complied
with the filed tariff was unreasoned and remanded the case back to the FERC for further proceedings on that issue. On February
4, 2022 the Illinois Attorney General and Public Citizen, Inc. filed a motion at the FERC requesting that the FERC on remand
reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to
Illinois or, in the alternative, initiate an evidentiary hearing and discovery. In June 2022, the FERC issued an order on remand
establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing
the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 planning resource auction. Although
the FERC directed the Office of Enforcement to file a remand report, the FERC stated in the June 2022 order that it is not
reopening the Office of Enforcement investigation. In September 2022, the Office of Enforcement filed its remand report
stating that the Office of Enforcement staff found during its investigation that Dynegy knowingly engaged in manipulative
behavior to set the Zone 4 price in the 2015-2016 PRA. In June 2023, the Company filed its initial brief and response to the
remand report, and in August 2023 the Company filed a reply to the initial briefs from other parties. In June 2024, the FERC
issued an order for an evidentiary hearing (or a trial before a FERC administrative law judge) to determine what the FERC cited
as "disputed issues of material fact" that it believes cannot be resolved on the existing record and, in October 2024, issued an
order dismissing our request for rehearing of the June 2024 order. We will continue to vigorously defend our position.
Other Matters
We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the
ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of
operations, liquidity, or financial condition.
140

Labor Contracts
We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by
collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel
engaged in lignite mining operations, lignite-, coal-, natural gas-, and nuclear-fueled generation operations, as well as some
battery operations, expire on various dates between February 2025 and March 2028, but remain effective thereafter unless and
until terminated by either party. While we cannot predict the outcome of labor contract negotiations, we do not expect any
changes in our existing agreements to have a material adverse effect on our results of operations, liquidity, or financial
condition.
Nuclear Insurance
Nuclear insurance includes nuclear liability coverage, property damage, nuclear accident decontamination, and accidental
premature decommissioning coverage, and accidental outage and/or extra expense coverage. We maintain nuclear insurance
that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title
10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is
available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy
exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of
insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity,
or financial condition.
With regard to nuclear liability coverage, the Act provides for financial protection for the public in the event of a
significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at
$16.2 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S.
Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $16.2 billion limit for a
single incident. As required, we insure against a possible nuclear incident at our nuclear facilities resulting in public nuclear-
related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective
payment plan known as Secondary Financial Protection (SFP).
Under the SFP, in the event of any single nuclear liability loss in excess of $500 million at any nuclear generation facility
in the U.S., each operating licensed reactor in the U.S. is subject to an assessment of up to $165.9 million. This approximately
$165.9 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment
scheduled to occur by November 2028. Assessments are currently limited to $24.7 million per operating licensed reactor per
year per incident. As of December 31, 2024, our maximum potential assessment under the industry retrospective plan would be
approximately $995.4 million per incident but no more than $148.2 million in any one year for each incident. The potential
assessment is triggered by a nuclear liability loss in excess of $500 million per accident at any nuclear facility.
The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain
at least $1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the
proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to,
and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature
decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance for our Comanche
Peak facility in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0 billion
(subject to a $5 million deductible per accident except for natural hazards which are subject to a $9.5 million deductible per
accident), and losses excluded or above such limits are self-insured. We maintain nuclear accident decontamination and reactor
damage stabilization insurance and non-nuclear accident related property damage for our Beaver Valley, Davis-Besse and Perry
facilities in the amount of $1.5 billion each (subject to a $20 million deductible per accident), and losses excluded or above such
limits are self-insured.
141

We also maintain Accidental Outage insurance to help cover the additional costs of obtaining replacement electricity from
another source if the units are out of service for more than twelve weeks as a result of covered direct physical damage.
Coverage at Comanche Peak provides for weekly payments per unit up to $4.5 million for the first 52 weeks and up to $2.7
million for a remaining 21 weeks for non-nuclear and up to $3.6 million for a remaining 71 weeks for nuclear property damage
outages. The total maximum coverage is $291 million for non-nuclear property damage and $490 million for nuclear property
damage outages. Coverage at Beaver Valley, Davis-Besse and Perry facilities provide for weekly payments per unit up to $2.5
million for the first 52 weeks and up to $1.5 million for a remaining 52 weeks for non-nuclear and up to $2 million for a
remaining 110 weeks for nuclear property damage outages. The total maximum coverage is $208 million for non-nuclear
property damage and $350 million for nuclear damage outages. There are two units at Comanche Peak and Beaver Valley, and
coverage amounts applicable to each unit will reduce to 80% if both units are out of service at the same time as a result of the
same accident.
16.
EQUITY
Common Stock
Issuances and Repurchases
Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2024, 2023,
and 2022 are reflected in the table below.
Shares
Issued
Treasury
Shares
Shares
Outstanding
Balance at December 31, 2021
532,929,476
(69,031,742)
463,897,734
Shares issued (a)
4,262,575
—
4,262,575
Shares retired
(12,979)
—
(12,979)
Shares repurchased (b)
—
(78,470,547)
(78,470,547)
Balance at December 31, 2022
537,179,072
(147,502,289)
389,676,783
Shares issued (a)
6,474,491
—
6,474,491
Shares retired
(18,391)
—
(18,391)
Shares repurchased (b)
—
(44,994,499)
(44,994,499)
Balance at December 31, 2023
543,635,172
(192,496,788)
351,138,384
Shares issued (a)
5,117,434
—
5,117,434
Shares repurchased (b)
—
(16,560,328)
(16,560,328)
Balance at December 31, 2024
548,752,606
(209,057,116)
339,695,490
____________
(a) Shares issued include share awards granted to nonemployee directors.
(b) Shares repurchased include 58,817, 318,632, and 78,087 of unsettled shares as of December 31, 2024, 2023, and 2022,
respectively.
Common Stock Dividends
Dividends are subject to declaration by the Board and may be subject to numerous factors at the time of declaration. These
factors include, but are not limited to, prevailing market conditions, Vistra's results of operations, financial condition and
liquidity, Delaware law, and any contractual limitations, such as the cumulative dividend requirements described in the
certificates of designation of our outstanding preferred stock. Dividends per common share totaled $0.8735, $0.8205, and
$0.7240 in the years ended December 31, 2024, 2023, and 2022, respectively.
In February 2025, the Board declared a quarterly dividend of $0.2235 per share of common stock that will be paid in
March 2025.
142

Share Repurchase Program
In October 2021, the Board authorized a share repurchase program (Share Repurchase Program). Under this program,
shares of the Company's common stock may be repurchased in open market transactions, privately negotiated transactions, or
other means in accordance with federal securities laws. The timing, number, and value of shares repurchased will be determined
at our discretion, considering factors such as capital allocation priorities, stock market price, general market and economic
conditions, legal requirements, and compliance with debt agreements and preferred stock certificates of designation.
Amount Authorized
for Share
Repurchases
(in billions)
Board Authorization Dates:
October 2021
$
2.00
August 2022
1.25
March 2023
1.00
February 2024
1.50
October 2024
1.00
Cumulative authorization at
December 31, 2024
$
6.75
The following table provides information about our repurchases of common stock for the period between January 1, 2022
and February 24, 2025.
$6.750 Billion Board Authorization
Total Number of
Shares
Repurchased
Average Price
Paid
Per Share
Amount Paid for
Shares
Repurchased
Amount Available
for Additional
Repurchases at the
End of the Period
(in millions, except share amounts and price paid per share)
Year Ended December 31, 2022
78,470,547
$
23.40
$
1,836
Year Ended December 31, 2023
44,994,499
27.89
1,255
Year Ended December 31, 2024
16,560,328
74.96
1,241
January 1, 2022 through December 31, 2024 (a)
140,025,374
$
30.94
$
4,332
$
2,009
January 1, 2025 through February 24, 2025
848,866
163.23
139
January 1, 2022 through February 24, 2025
140,874,240
$
31.74
$
4,471
$
1,870
____________
(a) Shares repurchased include 58,817 of unsettled shares for $8 million as of December 31, 2024.
Preferred Stock
The following is a summary of our cumulative redeemable preferred stock outstanding. In the event of liquidation or
dissolution of the Company, the payment of dividends and the distribution of assets to preferred stockholders takes precedence
over the Company's common stockholders.
Preferred
Stock
Series
Issuance
Date
Shares Issued
and
Outstanding (a)
Contractual
Rates
Earliest
Redemption
Date (b)
Date at Which
Dividend Rate
Becomes Floating
Floating Annual Rates
Series A
October 15,
2021
1,000,000
8.000 %
October 15,
2026
October 15,
2026
5-Year U.S. Treasury rate (subject
to floor of 1.07%) plus 6.93%
Series B
December 10,
2021
1,000,000
7.000 %
December 15,
2026
December 15,
2026
5-Year U.S. Treasury rate (subject
to floor of 1.26%) plus 5.74%
Series C
December 29,
2023
476,066
8.875 %
January 15,
2029
January 15,
2029
5-Year U.S. Treasury rate (subject
to floor of 3.83%) plus 5.045%
____________
(a) Series C Preferred Stock issued totaled 476,081 shares at December 31, 2023.
(b) Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.
143

Each series of preferred stock has a liquidation price of $1,000, plus accrued and unpaid dividends through their
redemption date. Preferred stock is not convertible into or exchangeable for any other securities of the Company and has limited
voting rights.
Preferred Stock Dividends
Preferred stock dividends are payable semiannually in arrears when declared by the Board. The following table
summarizes preferred stock dividends paid per share in the years ended December 31, 2024, 2023, and 2022.
Year Ended December 31,
Preferred Stock Series
2024
2023
2022
Series A Preferred Stock
$
80.00
$
80.00
$
80.00
Series B Preferred Stock
$
70.00
$
70.00
$
70.97
Series C Preferred Stock
$
48.32
In October 2024, the Board declared a semi-annual dividend of $44.375 per share of Series C Preferred Stock that was
paid in January 2025. In February 2025, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred
Stock that will be paid in April 2025.
17.
EARNINGS PER SHARE
Basic earnings per share available to common stockholders are based on the weighted average number of common shares
outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect
of all potential issuances of common shares under stock-based incentive compensation arrangements.
Year Ended December 31,
2024
2023
2022
(in millions, except share data)
Net income (loss) attributable to Vistra
$
2,659
$
1,493
$
(1,227)
Less cumulative dividends attributable to Series A Preferred Stock
(80)
(80)
(80)
Less cumulative dividends attributable to Series B Preferred Stock
(70)
(70)
(70)
Less cumulative dividends attributable to Series C Preferred Stock
(42)
—
—
Net income (loss) attributable to common stock — basic and diluted
2,467
1,343
(1,377)
Weighted average shares of common stock outstanding:
Basic
344,788,634
369,771,359
422,447,074
Dilutive securities: Stock-based incentive compensation plan
7,778,426
5,421,752
—
Diluted
352,567,060
375,193,110
422,447,074
Net income (loss) per weighted average share of common stock outstanding:
Basic
$
7.16
$
3.63
$
(3.26)
Diluted
$
7.00
$
3.58
$
(3.26)
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the
effect would have been antidilutive were immaterial in the year ended December 31, 2024 and were 392,218 and 8,292,647
shares for the years ended December 31, 2023 and 2022, respectively.
144

18.
STOCK-BASED COMPENSATION
Vistra 2016 Omnibus Incentive Plan
On the Effective Date, the Board adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an
aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee
directors, employees, and certain other persons. Following approval of the Board and approval by the stockholders at the 2019
and 2024 annual meetings of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares
reserved for issuance under the 2016 Incentive Plan to 37,500,000 and 43,000,000, respectively. The Board or any committee
duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to,
among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of
shares that are to be subject to such awards, and (c) establish the terms and conditions of awards, including the price (if any) to
be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock
options, RSUs, restricted stock, performance awards, and other forms of awards granted or denominated in shares of Vistra
common stock, as well as certain cash-based awards.
If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for
any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised
award shall again be available for awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards
or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited
for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan.
Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation. No awards
under the 2016 Incentive Plan have been settled in cash since the Effective Date.
As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the
2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets
under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers,
combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares
outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders.
Stock-Based Compensation Expense
Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows:
Year Ended December 31,
2024
2023
2022
(in millions)
Total stock-based compensation expense
$
100
$
77
$
65
Income tax benefit
(23)
(18)
(15)
Stock based-compensation expense, net of tax
$
77
$
59
$
50
Stock Options
Stock options outstanding at December 31, 2024 are all held by current or former employees. The following table
summarizes our stock option activity:
Year Ended December 31, 2024
Stock Options
(in thousands)
Weighted
Average
Exercise Price
Weighted Average
Remaining Contractual
Term (Years)
Aggregate
Intrinsic Value
(in millions)
Total outstanding at beginning of period
6,126
$
20.01
4.2
$
113.5
Exercised
(2,526) $
20.06
Total outstanding at end of period
3,600
$
19.97
3.5
$
424.4
Exercisable at December 31, 2024
3,600
$
19.97
3.5
$
424.4
As of December 31, 2024, there was no unrecognized compensation cost related to unvested stock options granted under
the 2016 Incentive Plan and no new options were issued in the three years ended December 31, 2024.
145

Restricted Stock Units
The following table summarizes our restricted stock unit activity:
Year Ended December 31, 2024
Restricted Stock
Units
(in thousands)
Weighted
Average Grant
Date Fair Value
Total nonvested at beginning of period
3,908
$
21.90
Granted
1,017
$
59.11
Vested
(1,785) $
22.20
Forfeited
(86) $
33.55
Total nonvested at end of period
3,054
$
34.30
As of December 31, 2024, $61 million of unrecognized compensation cost related to unvested restricted stock units
granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2.0
years.
Performance Stock Units
We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis. All PSUs have a
three year performance period and a payout opportunity of 0-200% of target (100%), which is intended to be settled in shares of
Vistra common stock. We recognized compensation expense associated with PSUs of $54 million, $36 million, and $22 million
for the years ended December 31, 2024, 2023, and 2022, respectively. As of December 31, 2024, we have $64 million of
unrecognized compensation cost associated with PSUs.
19.
SEGMENT INFORMATION
The operations of Vistra are aligned into five reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and
(v) Asset Closure. In the fourth quarter of 2024, we updated our reportable segments to reflect changes in how the Company's
CODM makes operating decisions, assesses performance, and allocates resources by removing the Sunset segment. The results
of the plants previously included in the Sunset segment are now reflected in the Texas and East segments based on their
respective geography.
Our Chief Executive Officer is our CODM. Our CODM reviews the results of these segments separately and allocates
resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets
are not regularly reviewed by the CODM for evaluating performance or allocating resources.
The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial
customers. Substantially all of these activities are conducted by TXU Energy, Ambit, Dynegy Energy Services, Homefield
Energy, Energy Harbor, and U.S. Gas & Electric across 16 states and the District of Columbia.
The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk
management activities, fuel procurement, and logistics management. The Texas segment represents results from all of Vistra's
electricity generation operations in the ERCOT market except for assets included in the Asset Closure segments. The East
segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid,
other than assets included in the Asset Closure segment, and includes operations in the PJM, MISO, ISO-NE, and NYISO
markets.
The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing
power plant site.
The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 6 for
additional information). Upon movement of generation plant assets to the Asset Closure segment, prior year results are
retrospectively adjusted, if the effects are material, for comparative purposes. Separately reporting the Asset Closure segment
provides management with better information related to the performance and earnings power of Vistra's ongoing operations and
facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and
mines.
146

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses,
interest, taxes and other expenses not allocated to our operating segments.
The accounting policies of the business segments are the same as those described in the summary of significant
accounting policies in Note 1. Our CODM uses more than one measure to assess segment performance, but primarily focuses
on Adjusted EBITDA. While we believe this is a useful metric in evaluating operating performance, it is not a metric defined by
U.S. GAAP and may not be comparable to non-GAAP metrics presented by other companies. Adjusted EBITDA is most
comparable to consolidated Net income (loss) prepared based on U.S. GAAP. The CODM uses net income in competitive
analysis by benchmarking to the Company's competitors and in evaluating drivers of segment profits available to the
Company's equity holders. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that
is, at market prices. Certain shared services costs are allocated to the segments. Substantially all income tax (expense) benefit is
recognized in Corporate and Other.
Year Ended December 31, 2024
Retail
Texas
East
West
Asset
Closure
Total
Reportable
Segments
Corporate
and Other
Total
(in millions)
Operating revenues
$ 12,797
$ 5,394
$ 5,661
$
877
$
1
$ 24,730
$ (7,506) $ 17,224
Fuel, purchased power costs, and
delivery fees
(10,276)
(1,596)
(2,698)
(221)
(3)
(14,794)
7,509
(7,285)
Operating costs
(159)
(996)
(1,103)
(72)
(81)
(2,411)
(3)
(2,414)
Selling, general, and administrative
expenses
(977)
(169)
(148)
(25)
(43)
(1,362)
(239)
(1,601)
Other segment items:
Depreciation and amortization
(114)
(581)
(996)
(86)
—
(1,777)
(66)
(1,843)
Interest expenses and related
charges
(54)
46
9
1
(4)
(2)
(898)
(900)
Income tax expense
—
—
—
—
—
—
(655)
(655)
Other (a)
(1)
35
177
(3)
14
222
64
286
Net income (loss)
$ 1,216
$ 2,133
$
902
$
471
$
(116) $
4,606
$ (1,794) $ 2,812
Capital expenditures, including
nuclear fuel and excluding growth
expenditures
$
4
$ 1,124
$
661
$
70
$
—
$
1,859
$
58
$ 1,917
Year Ended December 31, 2023
Retail
Texas
East
West
Asset
Closure
(b)
Total
Reportable
Segments
Corporate
and Other
Total
(in millions)
Operating revenues
$ 10,572
$ 3,979
$ 5,890
$
914
$
—
$ 21,355
$ (6,576) $ 14,779
Fuel, purchased power costs, and
delivery fees
(9,046)
(2,028)
(2,730)
(328)
(3)
(14,135)
6,578
(7,557)
Operating costs
(123)
(917)
(528)
(58)
(74)
(1,700)
(2)
(1,702)
Selling, general, and administrative
expenses
(858)
(140)
(127)
(24)
(34)
(1,183)
(125)
(1,308)
Other segment items:
Depreciation and amortization
(102)
(550)
(703)
(79)
—
(1,434)
(68)
(1,502)
Interest expenses and related
charges
(20)
21
(2)
8
(5)
2
(742)
(740)
Income tax expense
—
—
(1)
—
—
(1)
(507)
(508)
Other (a)
1
33
(50)
21
110
115
(85)
30
Net income (loss)
$
424
$
398
$ 1,749
$
454
$
(6) $
3,019
$ (1,527) $ 1,492
Capital expenditures, including
nuclear fuel and excluding growth
expenditures
$
1
$
750
$
362
$
366
$
—
$
1,479
$
58
$ 1,537
147

Year Ended December 31, 2022
Retail
Texas
East
West
Asset
Closure
(b)
Total
Reportable
Segments
Corporate
and Other
Total
(in millions)
Operating revenues
$ 9,455
$ 3,878
$ 4,429
$
336
$
384
$ 18,482
$ (4,754) $ 13,728
Fuel, purchased power costs, and
delivery fees
(7,169)
(3,052)
(4,132)
(481)
(322)
(15,156)
4,755
(10,401)
Operating costs
(143)
(832)
(482)
(42)
(145)
(1,644)
(1)
(1,645)
Selling, general, and administrative
expenses
(826)
(135)
(97)
(21)
(44)
(1,123)
(66)
(1,189)
Other segment items:
Interest expenses and related
charges
(14)
20
(6)
6
(3)
3
(371)
(368)
Depreciation and amortization
(145)
(541)
(768)
(42)
(31)
(1,527)
(69)
(1,596)
Income tax benefit
—
—
—
—
—
—
350
350
Other (a)
—
76
(71)
6
14
25
(114)
(89)
Net income (loss)
$ 1,158
$
(586) $ (1,127) $
(238) $
(147) $
(940) $
(270) $ (1,210)
Capital expenditures, including
nuclear fuel and excluding growth
expenditures
$
1
$
520
$
187
$
345
$
—
$
1,053
$
55
$ 1,108
____________
(a) Other includes impairment of long-lived assets, other income, other deductions, and the impacts of the Tax Receivable
Agreement.
(b) We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants
retired in 2022 and 2023. See Note 6 for additional information.
20.
SUPPLEMENTARY FINANCIAL INFORMATION
Other Income and Deductions
Year Ended December 31,
2024
2023
2022
(in millions)
Other income:
NDT net income (a)
$
170
$
—
$
—
Insurance settlements (b)
23
24
70
Gain on sale of land (c)
6
95
8
Gain on TRA settlement (d)
10
29
—
Interest income
65
86
19
All other
38
23
20
Total other income
$
312
$
257
$
117
Other deductions:
All other
$
21
$
14
$
4
Total other deductions
$
21
$
14
$
4
____________
(a) Includes interest, dividends, and net realized and unrealized gains and losses associated with NDTs of the PJM nuclear
facilities. Reported in the East segment.
(b) For the year ended December 31, 2024, $20 million reported in the Texas segment and $3 million reported in the West
segment. For the year ended December 31, 2023, $19 million reported in the West segment and $5 million in the Asset
Closure segment. For the year ended December 31, 2022, $62 million reported in the Texas segment, $6 million reported
in the West segment, $1 million reported in the Asset Closure segment, and $1 million reported in the Corporate and
Other non-segment.
148

(c) For the year ended December 31, 2024, reported in the Asset Closure segment. For the year ended December 31, 2023,
$94 million reported in the Asset Closure segment and $1 million reported in the Texas segment. For the year ended
December 31, 2022, reported in the Asset Closure segment.
(d) Reported in the Corporate and Other.
Inventories by Major Category
December 31,
2024
2023
(in millions)
Materials and supplies
$
533
$
289
Fuel stock
403
420
Natural gas in storage
34
31
Total inventories
$
970
$
740
Investments
December 31,
2024
2023
(in millions)
Nuclear decommissioning trusts
$
4,440
$
1,951
Assets related to employee benefit plans
14
28
Land investments
42
42
Other investments
16
14
Total investments
$
4,512
$
2,035
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
December 31,
2024
2023
(in millions)
Retirement and other employee benefits (Note 14)
$
224
$
247
Winter Storm Uri impact (a)
1
26
Identifiable intangible liabilities (Note 7)
155
131
Regulatory liability (b)
452
209
Operating lease liabilities
98
48
Finance lease liabilities
218
227
Liability for third-party remediation
8
17
Accrued severance costs
36
36
Other accrued expenses
64
58
Total other noncurrent liabilities and deferred credits
$
1,256
$
999
____________
(a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.
(b) As of December 31, 2024, the fair value of the assets contained in the Comanche Peak NDT was higher than the carrying
value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $452
million and $209 million, respectively, in other noncurrent liabilities and deferred credits.
149

Supplemental Cash Flow Information
The following table reconciles cash, cash equivalents and restricted cash reported in the consolidated statements of cash
flows to the amounts reported in the consolidated balance sheets at December 31, 2024 and 2023:
December 31,
2024
2023
(in millions)
Cash and cash equivalents
$
1,188
$
3,485
Restricted cash included in current assets (a)
28
40
Restricted cash included in noncurrent assets (a)
6
14
Total cash, cash equivalents and restricted cash
$
1,222
$
3,539
____________
(a) Restricted cash consists of amounts related to remediation escrow accounts. Vistra has transferred various asset retirement
obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra
deposits funds into escrow accounts, and the funds are released to the remediation company as milestones are reached in
the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations are
included in other current liabilities and other noncurrent liabilities and deferred credits.
The following table summarizes our supplemental cash flow information for the years ended December 31, 2024, 2023,
and 2022, respectively. Non-cash investing and financing activities also includes activity related to the Energy Harbor Merger.
See Note 2 for additional information.
Year Ended December 31,
2024
2023
2022
(in millions)
Cash payments related to:
Interest paid
$
987
$
636
$
581
Capitalized interest
(77)
(37)
(29)
Interest paid (net of capitalized interest)
$
910
$
599
$
552
Non-cash investing and financing activities:
Accrued property, plant, and equipment additions (a)
$
258
$
104
$
103
Issuance of Series C Preferred Stock as consideration for the repurchase of
TRA Rights with a carrying value of $506 million
$
—
$
476
$
—
Book value of property, plant, and equipment sold, including nuclear fuel
$
117
$
26
$
—
____________
(a) Represents property, plant, and equipment accruals during the period for which cash has not been paid as of the end of the
period.
For the years ended December 31, 2024, 2023, and 2022, we paid federal income taxes of $5 million, zero, and $1
million, respectively, paid state income taxes of $59 million, $44 million, and $33 million, respectively, and received state tax
refunds of $9 million, $13 million, and $8 million, respectively.
150

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the participation of our management, including the principal
executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and
procedures (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) in effect at December 31, 2024.
Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure
controls and procedures were effective as of that date.
Other than additional controls associated with the Energy Harbor Merger, there have been no changes in our internal
control over financial reporting (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) during the most
recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
VISTRA CORP.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Vistra Corp. is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Vistra
Corp.'s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in condition or the deterioration of compliance with procedures or policies.
The management of Vistra Corp. performed an evaluation of the effectiveness of the company's internal control over financial
reporting as of December 31, 2024 based on the Committee of Sponsoring Organizations of the Treadway Commission's
(COSO's) Internal Control - Integrated Framework (2013). Based on the review performed, management believes that as of
December 31, 2024 Vistra Corp.'s internal control over financial reporting was effective.
On March 1, 2024, a wholly owned subsidiary of Vistra Corp. merged with and into Energy Harbor, as further described in
Note 2. Energy Harbor's financial statements consolidated by Vistra Corp represent approximately 1% of the company's total
assets as of December 31, 2024 and approximately 11% of the company's total revenues for the year then ended, excluding
balance sheet accounts subjected to purchase accounting controls. As permitted by the SEC, management has elected to exclude
Energy Harbor from its assessment of the effectiveness of its internal control over financial reporting as of December 31, 2024.
The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial
statements of Vistra Corp. has issued an attestation report on Vistra Corp.'s internal control over financial reporting.
/s/ JAMES A. BURKE
/s/ KRISTOPHER E. MOLDOVAN
James A. Burke
Kristopher E. Moldovan
President and Chief Executive Officer
Chief Financial Officer
(Principal Executive Officer)
(Principal Financial Officer)
February 27, 2025
151

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Vistra Corp.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Vistra Corp. and subsidiaries (the “Company”) as of December
31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal
Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated financial statements as of and for the year ended December 31, 2024, of the Company and our
report dated February 27, 2025, expressed an unqualified opinion on those financial statements.
As described in Management’s Annual Report on Internal Control over Financial Reporting, management excluded from its
assessment the internal control over financial reporting at Energy Harbor Holdings LLC (formerly known as Energy Harbor
Corp.), which was acquired on March 1, 2024, and whose financial statements represent approximately 1% of total assets and
approximately 11% of revenues of the consolidated financial statement amounts, excluding balance sheet accounts subjected to
purchase accounting controls, as of and for the year ended December 31, 2024. Accordingly, our audit did not include the
internal control over financial reporting at Energy Harbor Holdings LLC.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s
Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s
internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 27, 2025
152

Item 9B. OTHER INFORMATION
During the three months ended December 31, 2024, none of our officers or directors adopted or terminated any contract,
instruction, or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense
conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement", except as set forth below.
On December 17, 2024, Kristopher Moldovan, Executive Vice President and Chief Financial Officer of the Company,
entered into a trading plan intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) of the Exchange Act (the
10b5-1 Plan). The 10b5-1 Plan provides for the potential exercise and sale of options for up to 139,925 shares of our common
stock pursuant to stock option awards that will be expiring over the next several years. Any sales are subject to certain price
limitations set forth in the 10b5-1 Plan such that the actual number of shares sold could vary if certain minimum stock prices
are not met. The 10b5-1 Plan will become effective on March 18, 2025 and will terminate on November 28, 2025, subject to
earlier termination as provided in the 10b5-1 Plan. The 10b5-1 Plan was entered into during an open insider trading window in
accordance with our Transactions in Securities Policy.
Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None.
153

PART III
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Code of Ethics
Vistra has adopted a code of ethics entitled "Vistra Code of Conduct" that applies to directors, officers, and employees,
including the chief executive officer and senior financial officers of Vistra. It may be accessed through the "Corporate
Governance" section of the Company's website at www.vistracorp.com. Vistra also elects to disclose the information required
by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics,"
through the Company's website and will disclose such events within four business days following the date of the amendment or
waiver, and such information will remain available on this website for at least a 12-month period. A copy of the "Vistra Code of
Conduct" is available in print to any stockholder who requests it.
Other information required by this Item is incorporated by reference to the similarly named section of Vistra Definitive
Proxy Statement for its 2025 Annual Meeting of Stockholders.
Item 11.
EXECUTIVE COMPENSATION
Information required by this Item is incorporated by reference to the similarly named section of Vistra's Definitive Proxy
Statement for its 2025 Annual Meeting of Stockholders.
Item 12.
SECURITY
OWNERSHIP
OF
CERTAIN
BENEFICIAL
OWNERS
AND
MANAGEMENT
AND
RELATED STOCKHOLDER MATTERS
Information required by this Item is incorporated by reference to the sections entitled "Beneficial Ownership of Common
Stock of the Company" in Vistra's Definitive Proxy Statement for its 2025 Annual Meeting of Stockholders.
Item 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by this Item is incorporated by reference to the sections entitled "Business Relationships and Related
Person Transactions Policy" and "Director Independence" in Vistra's Definitive Proxy Statement for its 2025 Annual Meeting
of Stockholders.
Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by this Item is incorporated by reference to the sections entitled "Principal Accountant Fees" in
Vistra's Definitive Proxy Statement for its 2025 Annual Meeting of Stockholders.
Deloitte & Touche LLP's PCAOB ID Number is 34.
154

PART IV
Item 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Our financial statements and financial statement schedules are incorporated under Part II, Item 8 of this annual report
on Form 10-K.
(b)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS
(Millions of Dollars)
Year Ended December 31,
2024
2023
2022
Depreciation and amortization
$
—
$
(15) $
(16)
Selling, general, and administrative expenses
(102)
(80)
(69)
Operating loss
(102)
(95)
(85)
Other income
28
31
6
Impacts of Tax Receivable Agreement
(5)
(164)
(128)
Loss before income tax benefit
(79)
(228)
(207)
Income tax benefit
17
58
47
Equity in earnings (losses) of subsidiaries, net of tax
2,721
1,663
(1,067)
Net income (loss)
$
2,659
$
1,493
$
(1,227)
See Notes to the Condensed Financial Statements.
155

VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(Millions of Dollars)
December 31,
2024
2023
ASSETS
Cash and cash equivalents
$
22
$
31
Trade accounts receivable — affiliates
13
—
Income taxes receivable
8
6
Total current assets
43
37
Investment in affiliated companies
4,670
4,507
Property, plant, and equipment — net
2
3
Accumulated deferred income taxes
960
1,086
Other noncurrent assets
3
—
Total assets
$
5,678
$
5,633
LIABILITIES AND EQUITY
Trade accounts payable
$
8
$
12
Accounts payable —affiliates
27
91
Accrued taxes
9
12
Other current liabilities
27
12
Total current liabilities
71
127
Tax Receivable Agreement obligations
14
164
Other noncurrent liabilities and deferred debits
10
20
Total liabilities
95
311
Total stockholders' equity
5,583
5,322
Total liabilities and equity
$
5,678
$
5,633
See Notes to the Condensed Financial Statements.
156

VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
2024
2023
2022
Cash flows — operating activities:
Cash used in operating activities
$
(37) $
(31) $
(27)
Cash flows — investing activities:
Dividend received from subsidiaries
1,705
1,625
1,775
Proceeds from sales of subsidiary transferable ITCs
150
—
—
Cash provided by investing activities
1,855
1,625
1,775
Cash flows — financing activities:
Stock repurchases
(1,266)
(1,245)
(1,949)
Dividends paid to common stockholders
(305)
(313)
(302)
Dividends paid to preferred stockholders
(173)
(150)
(151)
TRA Repurchase and tender offer - return of capital
(122)
—
—
Other, net
39
91
40
Cash used in financing activities
(1,827)
(1,617)
(2,362)
Net change in cash, cash equivalents and restricted cash
(9)
(23)
(614)
Cash, cash equivalents and restricted cash — beginning balance
31
54
668
Cash, cash equivalents and restricted cash — ending balance
$
22
$
31
$
54
See Notes to the Condensed Financial Statements.
NOTES TO CONDENSED FINANCIAL STATEMENTS
1.
BASIS OF PRESENTATION
The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of
operations and cash flows of Vistra Corp. (Parent). Certain information and footnote disclosures normally included in financial
statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules of the SEC. Because the
unconsolidated condensed financial statements do not include all of the information and footnotes required by U.S. GAAP, they
should be read in conjunction with the financial statements and related notes of Vistra Corp. and Subsidiaries included in the
annual report on Form 10-K for the year ended December 31, 2024. Vistra Corp.'s subsidiaries have been accounted for under
the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars
unless otherwise indicated.
Vistra Corp. (Parent) files a consolidated U.S. federal income tax return. Consolidated tax expenses or benefits and
deferred tax assets or liabilities have been allocated to the respective subsidiaries in accordance with the accounting rules that
apply to separate financial statements of subsidiaries.
2.
RESTRICTIONS ON SUBSIDIARIES
The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any
direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2024, Vistra
Operations can distribute approximately $8.2 billion to Vistra Corp. (Parent) under the Vistra Operations Credit Agreement
without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by
distributions made by Vistra Operations to Vistra Corp. (Parent) of approximately $1.705 billion, $1.625 billion, and $1.775
billion during the years ended December 31, 2024, 2023, and 2022, respectively. Additionally, Vistra Operations may make
distributions to Vistra Corp. (Parent) in amounts sufficient for Vistra Corp. (Parent) to make any payments required under the
TRA or the Tax Matters Agreement or, to the extent arising out of Vistra Corp. (Parent)'s ownership or operation of Vistra
Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2024, all of the
restricted net assets of Vistra Operations may be distributed to Vistra Corp. (Parent).
157

3.
GUARANTEES
Vistra Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that could require
performance or payment under certain conditions. As of December 31, 2024, there are no material outstanding claims related to
guarantee obligations of Vistra Corp. (Parent), and Vistra Corp. (Parent) does not anticipate it will be required to make any
material payments under these guarantees in the near term.
4.
DIVIDEND RESTRICTIONS
Under applicable law, Vistra Corp. (Parent) is prohibited from paying any dividend to the extent that immediately
following payment of such dividend there would be no statutory surplus or Vistra Corp. (Parent) would be insolvent.
Vistra Corp. (Parent) received $1.705 billion, $1.625 billion, and $1.775 billion in dividends from its consolidated
subsidiaries in the years ended December 31, 2024, 2023, and 2022, respectively.
(c)
EXHIBITS:
Vistra Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2024
(2)
Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.1
001-38086
Form 8-K
(filed March 7, 2023)
2.1
—
Transaction Agreement, dated March 6, 2023, by and among Vistra
Operations Company LLC, Black Pen Inc. and Energy Harbor
Corp.
(3(i))
Articles of Incorporation
3.1
001-38086
Form 8-K
(filed May 4, 2020)
3.1
—
Restated Certificate of Incorporation of Vistra Energy Corp. (now
known as Vistra Corp.)
3.2
001-38086
Form 8-K
(filed June 29, 2020)
3.1
—
Certificate
of
Amendment
of
the
Restated
Certificate
of
Incorporation of Vistra Energy Corp. (now known as Vistra Corp.),
effective July 2, 2020
3.3
001-38086
Form 8-K
(filed on October 15, 2021)
3.1
—
Series A Preferred Stock Certificate of Designation, filed with the
Secretary of State of Delaware on October 14, 2021
3.4
001-38086
Form 8-K (filed
on December 13, 2021)
3.1
—
Series B Preferred Stock Certificate of Designation, filed with the
Secretary of State of Delaware on December 9, 2021
3.5
001-38086
Form 8-K (filed
on January 4, 2024)
3.1
—
Series C Preferred Stock Certificate of Designation filed with the
Secretary of State of Delaware on December 29, 2023
(3(ii))
By-laws
3.6
001-38086
Form 8-K
(filed on November 5,
2024)
3.5
—
Amended and Restated Bylaws of Vistra Corp., effective October
30, 2024
(4)
Instruments Defining the Rights of Security Holders, Including Indentures
4.1
001-38086
Form 8-K
(filed on August 23, 2018)
4.1
—
Indenture for 5.500% Senior Note due 2026, dated as of August 22,
2018, among Vistra Operations Company LLC, as issuer, the
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee
4.2
001-38086
Form 8-K
(filed on August 23, 2018)
4.2
—
Form of Rule 144A Global Security for 5.500% Senior Note due
2026 (included in Exhibit 4.1)
Exhibits
Previously Filed With File
Number*
As
Exhibit
158

4.3
001-38086
Form 8-K
(filed on August 23, 2018)
4.3
—
Form of Regulation S Global Security for 5.500% Senior Note due
2026 (included in Exhibit 4.1)
4.4
001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.5
—
First Supplemental Indenture for the 5.500% Senior Notes due
2026, dated August 30, 2019, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.5
001-38086
Form 10-K (Year ended
December 31, 2019) (filed
on February 28, 2020)
4.36
—
Second Supplemental Indenture for the 5.500% Senior Notes due
2026,
dated
October
25,
2019,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.6
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.5
—
Third Supplemental Indenture for the 5.500% Senior Notes due
2026,
dated
January
31,
2020,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.7
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.6
—
Fourth Supplemental Indenture for the 5.500% Senior Notes due
2026, dated March 26, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.8
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.8
—
Fifth Supplemental Indenture for the 5.500% Senior Notes due
2026, dated October 7, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.9
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.9
—
Sixth Supplemental Indenture for the 5.500% Senior Notes due
2026, dated January 8, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.10
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
4.3
—
Seventh Supplemental Indenture for the 5.500% Senior Notes due
2026, dated July 29, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.11
001-38086
Form 10-K (Year ended
December 31, 2021) (filed
on February 25, 2022)
4.11
—
Eighth Supplemental Indenture for the 5.500% Senior Notes due
2026,
dated
December
28,
2021,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.12
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
4.12
—
Ninth Supplemental Indenture for the 5.500% Senior Notes due
2026,
dated
December
15,
2022,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.13
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
4.1
—
Tenth Supplemental Indenture for the 5.500% Senior Notes due
2026, dated July 31, 2023, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.14
**
—
Eleventh Supplemental Indenture for the 5.500% Senior Notes due
2026, dated October 20, 2023, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
4.15
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.6
—
Twelfth Supplemental Indenture for 5.500% Senior Notes due
2026, dated March 29, 2024, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
4.16
001-38086
Form 8-K
(filed on February 6, 2019)
4.1
—
Indenture for 5.625% Senior Note due 2027, dated as of February 6,
2019, among Vistra Operations Company LLC, as issuer, the
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee
Exhibits
Previously Filed With File
Number*
As
Exhibit
159

4.17
001-38086
Form 8-K
(filed on February 6, 2019)
4.2
—
Form of Rule 144A Global Security for 5.625% Senior Note due
2027 (included in Exhibit 4.1)
4.18
001-38086
Form 8-K
(filed on February 6, 2019)
4.3
—
Form of Regulation S Global Security for 5.625% Senior Note due
2027 (included in Exhibit 4.1)
4.19
001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.6
—
First Supplemental Indenture for the 5.625% Senior Notes due
2027, dated August 30, 2019, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.20
001-38086
Form 10-K (Year ended
December 31, 2019) (filed
on February 28, 2020)
4.41
—
Second Supplemental Indenture for the 5.625% Senior Notes due
2027,
dated
October
25,
2019,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.21
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.7
—
Third Supplemental Indenture for the 5.625% Senior Notes due
2027,
dated
January
31,
2020,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.22
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.8
—
Fourth Supplemental Indenture for the 5.625% Senior Notes due
2027, dated March 26, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.23
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.17
—
Fifth Supplemental Indenture for the 5.625% Senior Notes due
2027, dated October 7, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.24
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.18
—
Sixth Supplemental Indenture for the 5.625% Senior Notes due
2027, dated January 8, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.25
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
4.4
—
Seventh Supplemental Indenture for the 5.625% Senior Notes due
2027, dated July 29, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.26
001-38086
Form 10-K (Year ended
December 31, 2021) (filed
on February 25, 2022)
4.22
—
Eighth Supplemental Indenture for the 5.625% Senior Notes due
2027,
dated
December
28,
2021,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.27
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
4.24
—
Ninth Supplemental Indenture for the 5.625% Senior Notes due
2027,
dated
December
15,
2022,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.28
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
4.2
—
Tenth Supplemental Indenture for the 5.625% Senior Notes due
2027, dated July 31, 2023, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.29
**
—
Eleventh Supplemental Indenture for the 5.625% Senior Notes due
2027, dated October 20, 2023, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
4.30
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.7
—
Twelfth Supplemental Indenture for 5.625% Senior Notes due
2027, dated March 29, 2024, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
Exhibits
Previously Filed With File
Number*
As
Exhibit
160

4.31
001-38086
Form 8-K
(filed on June 24, 2019)
4.1
—
Indenture for 5.00% Senior Notes due 2027, dated as of June 21,
2019, among Vistra Operations Company LLC, as Issuer, the
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee
4.32
001-38086
Form 8-K
(filed on June 24, 2019)
4.2
—
Form of Rule 144A Global Security for 5.00% Senior Notes due
2027 (included in Exhibit 4.1)
4.33
001-38086
Form 8-K
(filed on June 24, 2019)
4.3
—
Form of Regulation S Global Security for 5.00% Senior Notes due
2027 (included in Exhibit 4.1)
4.34
001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.7
—
First Supplemental Indenture for the 5.000% Senior Notes due
2027, dated August 30, 2019, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.35
001-38086
Form 10-K (Year ended
December 31, 2019) (filed
on February 28, 2020)
4.46
—
Second Supplemental Indenture for the 5.000% Senior Notes due
2027,
dated
October
25,
2019,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.36
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.9
—
Third Supplemental Indenture for the 5.000% Senior Notes due
2027,
dated
January
31,
2020,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.37
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.10
—
Fourth Supplemental Indenture for the 5.000% Senior Notes due
2027, dated March 26, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.38
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.26
—
Fifth Supplemental Indenture for the 5.000% Senior Notes due
2027, dated October 7, 2020, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.39
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.27
—
Sixth Supplemental Indenture for the 5.000% Senior Notes due
2027, dated January 8, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.40
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
4.5
—
Seventh Supplemental Indenture for the 5.000% Senior Notes due
2027, dated July 29, 2021, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.41
001-38086
Form 10-K (Year ended
December 31, 2021) (filed
on February 25, 2022)
4.33
—
Eighth Supplemental Indenture for the 5.000% Senior Notes due
2027,
dated
December
28,
2021,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.42
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
4.36
—
Ninth Supplemental Indenture for the 5.000% Senior Notes due
2027,
dated
December
15,
2022,
among
the
Guaranteeing
Subsidiaries, the Company, the Subsidiary Guarantors and the
Trustee
4.43
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
4.3
—
Tenth Supplemental Indenture for the 5.000% Senior Notes due
2027, dated July 31, 2023, among the Guaranteeing Subsidiaries,
the Company, the Subsidiary Guarantors and the Trustee
4.44
**
—
Eleventh Supplemental Indenture for the 5.000% Senior Notes due
2027, dated October 20, 2023, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
Exhibits
Previously Filed With File
Number*
As
Exhibit
161

4.45
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.8
—
Twelfth Supplemental Indenture for 5.00% Senior Notes due 2027,
dated March 29, 2024, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors
and the Trustee
4.46
001-38086
Form 8-K
(filed on June 17, 2019)
4.1
—
Indenture, dated as of June 11, 2019, between Vistra Operations
Company
LLC,
as
Issuer,
and
Wilmington
Trust,
National
Association, as Trustee
4.47
001-38086
Form 8-K
(filed on June 17, 2019)
4.2
—
Supplemental Indenture for 3.55% Senior Secured Notes due 2024
and 4.30% Senior Secured Notes Due 2029, dated as of June 11,
2019, among Vistra Operations Company LLC, as Issuer, the
Subsidiary Guarantors (as defined therein), and Wilmington Trust,
National Association, as Trustee
4.48
001-38086
Form 8-K
(filed on June 17, 2019)
4.4
—
Form of Rule 144A Global Security for 4.30% Senior Notes due
2029 (included in Exhibit 4.2)
4.49
001-38086
Form 8-K
(filed on June 17, 2019)
4.6
—
Form of Regulation S Global Security for 4.30% Senior Notes due
2029 (included in Exhibit 4.2)
4.50
001-38086
Form 10-Q (Quarter ended
September 30, 2019) (filed
on November 5, 2019)
4.8
—
Second Supplemental Indenture for 3.55% Senior Secured Notes
due 2024 and 4.30% Senior Secured Notes due 2029, dated as of
August 30, 2019, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors
and the Trustee
4.51
001-38086
Form 8-K (filed
on November 21, 2019)
4.1
—
Third Supplemental Indenture for 3.55% Senior Secured Notes due
2024 and 4.30% Senior Secured Notes due 2029, dated as of
October 25, 2019, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, Subsidiary Guarantors and
the Trustee
4.52
001-38086
Form 8-K (filed
on November 21, 2019)
4.2
—
Fourth Supplemental Indenture, dated as of November 15, 2019,
among Vistra Operations Company LLC, as Issuer, the Subsidiary
Guarantors (as defined therein), and Wilmington Trust, National
Association, as Trustee
4.53
001-38086
Form 8-K (filed
on November 21, 2019)
4.3
—
Form of Rule 144A Global Security for 3.70% Senior Note due
2027 (included in Exhibit 4.2)
4.54
001-38086
Form 8-K (filed
on November 21, 2019)
4.4
—
Form of Regulation S Global Security for 3.70% Senior Note due
2027 (included in Exhibit 4.2)
4.55
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.11
—
Fifth Supplemental Indenture for 3.55% Senior Secured Notes due
2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
Secured Notes due 2029, dated as of January 31, 2020, among
Vistra Operations Company LLC, as Issuer, the Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee
4.56
001-38086
Form 10-Q (Quarter ended
March 31, 2020) (filed on
May 5, 2020)
4.12
—
Sixth Supplemental Indenture for 3.55% Senior Secured Notes due
2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
Secured Notes due 2029, dated as of March 26, 2020, among Vistra
Operations
Company
LLC,
as
Issuer,
the
Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee
4.57
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.41
—
Seventh Supplemental Indenture for 3.55% Senior Secured Notes
due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
Secured Notes due 2029, dated as of October 7, 2020, among Vistra
Operations
Company
LLC,
as
Issuer,
the
Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee
Exhibits
Previously Filed With File
Number*
As
Exhibit
162

4.58
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.42
—
Eighth Supplemental Indenture for 3.55% Senior Secured Notes
due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
Secured Notes due 2029, dated as of January 8, 2021, among Vistra
Operations
Company
LLC,
as
Issuer,
the
Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee
4.59
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
4.6
—
Ninth Supplemental Indenture for 3.55% Senior Secured Notes due
2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
Secured Notes due 2029, dated as of July 29, 2021, among Vistra
Operations
Company
LLC,
as
Issuer,
the
Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee
4.60
001-38086
Form 10-K (Year ended
December 31, 2021) (filed
on February 25, 2022)
4.50
—
Tenth Supplemental Indenture for 3.55% Senior Secured Notes due
2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior
Secured Notes due 2029, dated as of December 28, 2021, among
Vistra Operations Company LLC, as Issuer, the Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee
4.61
001-38086
Form 8-K
(filed on May 16, 2022)
4.1
—
Eleventh Supplemental Indenture for 4.875% Senior Secured Notes
due 2024 and 5.125% Senior Secured Notes due 2025, dated as of
May 13, 2022, among Vistra Operations Company LLC, as Issuer,
the Subsidiary Guarantors and the Trustee
4.62
001-38086
Form 8-K
(filed on May 16, 2022)
4.4
—
Form of Rule 144A Global Security for 5.125% Senior Note due
2025 (included in Exhibit 4.1)
4.63
001-38086
Form 8-K
(filed on May 16, 2022)
4.5
—
Form of Regulation S Global Security for 5.125% Senior Note due
2025 (included in Exhibit 4.1)
4.64
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
4.55
—
Twelfth Supplemental Indenture for 3.55% Senior Secured Notes
due 2024, 3.70% Senior Secured Notes due 2027, 4.30% Senior
Secured Notes due 2029, 4.875% Senior Secured Notes due 2024
and 5.125% Senior Secured Notes due 2025, dated as of December
15, 2022, among Vistra Operations Company LLC, as Issuer, the
Guaranteeing Subsidiaries, the Subsidiary Guarantors and the
Trustee
4.65
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
4.4
—
Thirteenth Supplemental Indenture for 3.55% Senior Secured Notes
due 2024, 3.70% Senior Secured Notes due 2027, 4.30% Senior
Secured Notes due 2029, 4.875% Senior Secured Notes due 2024
and 5.125% Senior Secured Notes due 2025, dated as of July 31,
2023, among Vistra Operations Company LLC, as Issuer, the
Guaranteeing Subsidiaries, the Subsidiary Guarantors and the
Trustee
4.66
001-38086
Form 8-K
(filed on October 2, 2023)
4.1
—
Fourteenth Supplemental Indenture for the 6.950% Senior Secured
Notes due 2033, dated as of September 26, 2023, among Vistra
Operations
Company
LLC,
as
Issuer,
the
Guaranteeing
Subsidiaries, the Subsidiary Guarantors and the Trustee
4.67
**
—
Fifteenth Supplemental Indenture for 3.55% Senior Secured Notes
due 2024, 4.30% Senior Secured Notes due 2029, 3.70% Senior
Secured Notes due 2027, 4.875% Senior Secured Notes due 2024,
5.125% Senior Secured Notes due 2025 and 6.950% Senior Secured
Notes due 2033, dated October 20, 2023, among Vistra Operations
Company LLC, as Issuer, the Guaranteeing Subsidiaries, the
Subsidiary Guarantors and the Trustee
4.68
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.9
—
Sixteenth Supplemental Indenture for 3.55% Senior Secured Notes
due 2024, 4.30% Senior Secured Notes due 2029, 3.70% Senior
Secured Notes due 2027, 4.875% Senior Secured Notes due 2024,
5.125% Senior Secured Notes due 2025 and 6.950% Senior Secured
Notes due 2033, dated March 29, 2024, among Vistra Operations
Company LLC, as Issuer, the Guaranteeing Subsidiaries, the
Subsidiary Guarantors and the Trustee
Exhibits
Previously Filed With File
Number*
As
Exhibit
163

4.69
001-38086
Form 8-K
(filed on April 18, 2024)
4.1
—
Seventeenth Supplemental Indenture, dated as of April 12, 2024,
between Vistra Operations Company LLC, as Issuer, the Subsidiary
Guarantors, and Wilmington Trust, National Association, as
Trustee
4.70
001-38086
Form 8-K
(filed on December 9,
2024)
4.1
—
Eighteenth Supplemental Indenture, dated as of December 4, 2024,
between Vistra Operations Company LLC, as Issuer, the Subsidiary
Guarantors, and Wilmington Trust, National Association, as
Trustee
4.71
001-38086
Form 8-K
(filed on December 9,
2024)
4.2
—
Form of Rule 144A Global Security for 5.050% Senior Secured
Note due 2026 (included in Exhibit 4.1)
4.72
001-38086
Form 8-K
(filed on December 9,
2024)
4.3
—
Form of Rule 144A Global Security for 5.700% Senior Secured
Note due 2034 (included in Exhibit 4.1)
4.73
001-38086
Form 8-K
(filed on December 9,
2024)
4.4
—
Form of Regulation S Global Security for 5.050% Senior Secured
Note due 2026 (included in Exhibit 4.1)
4.74
001-38086
Form 8-K
(filed on December 9,
2024)
4.5
—
Form of Regulation S Global Security for 5.700% Senior Secured
Note due 2034 (included in Exhibit 4.1)
4.75
001-38086
Form 8-K
(filed on April 18, 2024)
4.2
—
Indenture, dated as of April 12, 2024, between Vistra Operations
Company
LLC,
as
Issuer,
the
Subsidiary
Guarantors,
and
Wilmington Trust, National Association, as Trustee
4.76
001-38086
Form 8-K
(filed on April 18, 2024)
4.3
—
Form of Rule 144A Global Security for 6.000% Senior Secured
Note due 2034 (included in Exhibit 4.1)
4.77
001-38086
Form 8-K
(filed on April 18, 2024)
4.4
—
Form of Rule 144A Global Security for 6.875% Senior Note due
2032 (included in Exhibit 4.2)
4.78
001-38086
Form 8-K
(filed on April 18, 2024)
4.5
—
Form of Regulation S Global Security for 6.000% Senior Secured
Note due 2034 (included in Exhibit 4.1)
4.79
001-38086
Form 8-K
(filed on April 18, 2024)
4.6
—
Form of Regulation S Global Security for 6.875% Senior Note due
2032 (included in Exhibit 4.2)
4.80
001-38086
Form 8-K
(filed on October 2, 2023)
4.2
—
Indenture for the 7.750% Senior Unsecured Notes due 2031, dated
as of September 26, 2023, by and among Vistra Operations
Company LLC, as Issuer, the Subsidiary Guarantors and the
Trustee
4.81
001-38086
Form 8-K
(filed on October 2, 2023)
4.3
—
Form of Rule 144A Global Security for 6.950% Senior Secured
Note due 2033 (included in Exhibit 4.1)
4.82
001-38086
Form 8-K
(filed on October 2, 2023)
4.4
—
Form of Regulation S Global Security for 6.950% Senior Secured
Note due 2033 (included in Exhibit 4.1)
4.83
001-38086
Form 8-K
(filed on October 2, 2023)
4.5
—
Form of Rule 144A Global Security for 7.750% Senior Unsecured
Note due 2031 (included in Exhibit 4.2)
Exhibits
Previously Filed With File
Number*
As
Exhibit
164

4.84
001-38086
Form 8-K
(filed on October 2, 2023)
4.6
—
Form
of
Regulation
S
Global
Security
for
7.750%
Senior
Unsecured Note due 2031 (included in Exhibit 4.2)
4.85
**
—
First Supplemental Indenture for 7.750% Senior Secured Notes due
2031, dated October 20, 2023, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
4.86
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.3
—
Second Supplemental Indenture for 7.750% Senior Secured Notes
due 2031, dated March 29, 2024, among Vistra Operations
Company LLC, as Issuer, the Guaranteeing Subsidiaries, the
Subsidiary Guarantors and the Trustee
4.87
001-38086
Form 8-K
(filed on May 11, 2021)
4.1
—
Indenture for 4.375% Senior Notes due 2029, dated as of May 10,
2021, between Vistra Operations Company LLC, as Issuer, the
Subsidiary
Guarantors,
and
Wilmington
Trust,
National
Association, as Trustee
4.88
001-38086
Form 8-K
(filed on May 11, 2021)
4.2
—
Form of Rule 144A Global Security for 4.375% Senior Notes due
2029 (included in Exhibit 4.1)
4.89
001-38086
Form 8-K
(filed on May 11, 2021)
4.3
—
Form of Regulation S Global Security for 4.375% Senior Notes due
2029 (included in Exhibit 4.1)
4.90
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
4.7
—
First Supplemental Indenture for the 4.375% Senior Notes due
2029, dated July 29, 2021, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
4.91
001-38086
Form 10-K (Year ended
December 31, 2021) (filed
on February 25, 2022)
4.55
—
Second Supplemental Indenture for the 4.375% Senior Notes due
2029,
dated
December
28,
2021,
among
Vistra
Operations
Company LLC, as Issuer, the Guaranteeing Subsidiaries, the
Subsidiary Guarantors and the Trustee
4.92
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
4.65
—
Third Supplemental Indenture for the 4.375% Senior Notes due
2029,
dated
December
15,
2022,
among
Vistra
Operations
Company LLC, as Issuer, the Guaranteeing Subsidiaries, the
Subsidiary Guarantors and the Trustee
4.93
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
4.5
—
Fourth Supplemental Indenture for the 4.375% Senior Notes due
2029, dated July 31, 2023, among Vistra Operations Company
LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary
Guarantors and the Trustee
4.94
**
—
Fifth Supplemental Indenture for 4.375% Senior Notes due 2029,
dated October 20, 2023, among Vistra Operations Company LLC,
as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors
and the Trustee
4.95
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.5
—
Sixth Supplemental Indenture for 4.375% Senior Notes due 2029,
dated March 29, 2024, among Vistra Operations Company LLC, as
Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors
and the Trustee
4.96
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.16
—
First Supplemental Indenture, dated as of June 15, 2009, under the
Open-End Mortgage, General Mortgage Indenture and Deed of
Trust, dated as of June 1, 2009
4.97
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.17
—
Second Supplemental Indenture, dated as of June 30, 2009, under
the Open-End Mortgage, General Mortgage Indenture and Deed of
Trust, dated as of June 1, 2009
Exhibits
Previously Filed With File
Number*
As
Exhibit
165

4.98
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.18
—
Fifth Supplemental Indenture, dated as of August 15, 2016, under
the Open-End Mortgage, General Mortgage Indenture and Deed of
Trust, dated as of June 1, 2009
4.99
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.19
—
Eighth Supplemental Indenture, dated as of August 15, 2016, under
the Open-End Mortgage, General Mortgage Indenture and Deed of
Trust, dated as of June 19, 2008
4.100
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.20
—
Open-End Mortgage, General Mortgage Indenture and Deed of
Trust, dated as of June 1, 2009
4.101
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.21
—
Open-End Mortgage, General Mortgage Indenture and Deed of
Trust, dated as of June 19, 2008
4.102
001-38086
Form 8-K
(filed on August 23, 2018)
4.7
—
Purchase and Sale Agreement dated as of August 21, 2018, between
TXU Energy Retail Company LLC as originator, and TXU Energy
Receivables Company LLC, as purchaser
4.103
001-38086
Form 8-K
(filed on August 23, 2018)
4.8
—
Receivable Purchase Agreement dated as of August 21, 2018,
among TXU Energy Receivables Company LLC, as seller, TXU
Energy Retail Company LLC, as servicer, Vistra Operations
Company LLC, as performance guarantor, certain purchaser agents
and purchasers named therein and Credit Agricole Corporate and
Investment Bank, as administrator
4.104
001-38086
Form 8-K
(filed on April 5, 2019)
4.1
—
First Amendment to Purchase and Sale Agreement, dated as of
April 1, 2019, among TXU Energy Retail Company LLC, Dynegy
Energy Services, LLC, and Dynegy Energy Services (East), LLC,
each as an originator, and TXU Energy Receivables Company LLC,
as purchaser
4.105
001-38086
Form 10-Q (Quarter ended
June 30, 2019) (filed on
August 2, 2019)
4.12
—
Second Amendment to Purchase and Sale Agreement, dated as of
June 3, 2019, among TXU Energy Retail Company LLC, Dynegy
Energy Services, LLC, and Dynegy Energy Services (East), LLC,
each as an originator, and TXU Energy Receivables Company LLC,
as purchaser
4.106
001-38086
Form 8-K
(filed on July 19, 2019)
4.1
—
Third Amendment to Purchase and Sale Agreement, dated as of
July 15, 2019, among TXU Energy Retail Company LLC, Dynegy
Energy Services, LLC, and Dynegy Energy Services (East), LLC,
each as an originator, and TXU Energy Receivables Company LLC,
as purchaser
4.107
001-38086
Form 8-K
(filed on October 16, 2020)
4.1
—
Fourth Amendment to Purchase and Sale Agreement, dated as of
October 9, 2020, among TXU Energy Retail Company LLC, as an
originator and servicer, the other originators named therein, and
TXU Energy Receivables Company LLC, as purchaser
4.108
001-38086
Form 8-K
(filed on December 28,
2020)
4.1
—
Fifth Amendment to Purchase and Sale Agreement, dated as of
December 21, 2020, among TXU Energy Retail Company LLC,
certain originators named therein, and TXU Energy Receivables
Company LLC, as purchaser
4.109
001-38086
Form of 8-K
(filed on April 9, 2024)
4.2
—
Sixth Amendment to Purchase and Sale Agreement, dated as of
April 8, 2024, among TXU Receivables, as buyer, TXU Retail, as
servicer, certain originators named therein and Credit Agricole
Corporate and Investment Bank, as administrator
Exhibits
Previously Filed With File
Number*
As
Exhibit
166

4.110
001-38086
Form 8-K
(filed on April 5, 2019)
4.2
—
First Amendment to Receivables Purchase Agreement, dated as of
April 1, 2019, among TXU Energy Receivables Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.111
001-38086
Form 10-Q (Quarter ended
June 30, 2019) (filed on
August 2, 2019)
4.13
—
Second Amendment to Receivables Purchase Agreement, dated as
of June 3, 2019, among TXU Energy Receivables Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.112
001-38086
Form 8-K
(filed on July 19, 2019)
4.2
—
Third Amendment to Receivables Purchase Agreement, dated as of
July 15, 2019, among TXU Energy Receivables Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.113
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
4.76
—
Fourth Amendment to Receivables Purchase Agreement, dated as
of November 15, 2019, among TXU Energy Receivables Company
LLC, as seller, TXU Energy Retail Company LLC, as servicer,
Vistra Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.114
001-38086
Form 8-K
(filed on July 16, 2020)
4.1
—
Fifth Amendment to Receivables Purchase Agreement, dated as of
July 13, 2020, among TXU Energy Receivables Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.115
001-38086
Form 8-K
(filed on October 16, 2020)
4.2
—
Sixth Amendment to Receivables Purchase Agreement, dated as of
October 9, 2020, among TXU Energy Receivables Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator
4.116
001-38086
Form 8-K
(filed on December 28,
2020)
4.2
—
Seventh Amendment to Receivables Purchase Agreement, dated as
of December 21, 2020, among TXU Energy Receivables Company
LLC, as seller, TXU Energy Retail Company LLC, as servicer,
Vistra Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator
4.117
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
4.56
—
Eighth Amendment to Receivables Purchase Agreement, dated as
of February 19, 2020, among TXU Energy Receivables Company
LLC, as seller, TXU Energy Retail Company LLC, as servicer,
Vistra Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator
4.118
001-38086
Form 10-Q (Quarter ended
March 31, 2021) (filed on
May 4, 2021)
4.6
—
Ninth Amendment to Receivables Purchase Agreement, dated as of
March 26, 2021, among TXU Energy Receivables Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator
Exhibits
Previously Filed With File
Number*
As
Exhibit
167

4.119
001-38086
Form 8-K
(filed on July 15, 2021)
4.1
—
Tenth Amendment to Receivables Purchase Agreement, dated as of
July 9, 2021, among TXU Energy Receivables Company LLC, as
seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator
4.120
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
4.2
—
Eleventh Amendment to Receivables Purchase Agreement, dated as
of July 16, 2021, among TXU Energy Receivables Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator
4.121
001-38086
Form of 8-K
(filed on July 15, 2022)
4.1
—
Twelfth Amendment to Receivables Purchase Agreement, dated as
of July 11, 2022, among TXU Energy Receivables Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein, and Credit Agricole
Corporate and Investment Bank, as administrator
4.122
001-38086
Form of 8-K
(filed on July 17, 2023)
4.1
—
Thirteenth Amendment to Receivables Purchase Agreement, dated
as of July 11, 2023, among TXU Energy Receivables Company
LLC, as seller, TXU Energy Retail Company LLC, as servicer,
Vistra Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.123
001-38086
Form of 8-K
(filed on April 9, 2024)
4.1
—
Fourteenth Amendment to Receivables Purchase Agreement, dated
as of April 8, 2024, among TXU Receivables, as seller, TXU
Retail,
as
servicer,
Vistra
Operations
Company
LLC,
as
performance guarantor, certain purchaser agents and purchasers
named therein and Credit Agricole Corporate and Investment Bank,
as administrator
4.124
001-38086
Form of 8-K
(filed on July 12, 2024)
4.1
—
Fifteenth Amendment to Receivables Purchase Agreement, dated as
of July 11, 2024, among TXU Energy Receivables Company LLC,
as seller, TXU Energy Retail Company LLC, as servicer, Vistra
Operations Company LLC, as performance guarantor, certain
purchaser agents and purchasers named therein and Credit Agricole
Corporate and Investment Bank, as administrator
4.125
001-38086
Form of 8-K
(filed on June 22, 2023)
4.1
—
Facility Agreement, dated June 15, 2023, among Palomino Funding
Trust I, Vistra Operations Company LLC, the subsidiary guarantors
party thereto and Bank of New York Mellon Trust Company, N.A.,
as senior secured notes trustee
4.126
001-38086
Form of 8-K
(filed on June 22, 2023)
4.2
—
Amended and Restated Declaration of Trust of Palomino Funding
Trust I, dated June 15, 2023, among Vistra Operations Company
LLC, as depositor, The Bank of New York Mellon Trust Company,
N.A., as trustee, BNY Mellon Trust of Delaware, as Delaware
trustee, and Vistra Operations Company LLC, solely for the
purposes of Sections 5.10(b) and (f), Sections 5.17(b), (d), (e) and
(f) and Section 10.4(c)
4.127
001-38086
Form of 8-K
(filed on June 22, 2023)
4.3
—
Indenture, dated June 15, 2023, between Vistra Operations
Company LLC, as issuer, and The Bank of New York Mellon Trust
Company, N.A., as trustee
4.128
001-38086
Form of 8-K
(filed on June 22, 2023)
4.4
—
Supplemental Indenture, dated June 15, 2023, between Vistra
Operations Company LLC, as issuer, the subsidiary guarantors
party thereto and The Bank of New York Mellon Trust Company,
N.A., as trustee
4.129
001-38086
Form of 8-K
(filed on June 22, 2023)
4.5
—
Form of 7.233% Senior Secured Notes due 2028 (included in
Exhibit 4.4)
Exhibits
Previously Filed With File
Number*
As
Exhibit
168

4.130
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
4.6
—
Second Supplemental Indenture for the 7.233% Senior Secured
Notes due 2028, dated August 3, 2023, among Vistra Operations
Company LLC, as Issuer, the subsidiary guarantors party thereto
and the Bank of New York Mellon Trust Company, N.A., as trustee
4.131
**
—
Third Supplemental Indenture for 7.233% Senior Secured Notes
due 2028, dated October 20, 2023, among Vistra Operations
Company LLC, as Issuer, the Guaranteeing Subsidiaries, the
Subsidiary Guarantors and the Bank of New York Mellon Trust
Company, N.A., as trustee
4.132
001-38086
Form 10-Q (Quarter ended
March 31, 2024) (filed on
May 10, 2024)
4.4
—
Fourth Supplemental Indenture for 7.233% Senior Secured Notes
due 2028, dated March 29, 2024, among Vistra Operations
Company LLC, as Issuer, the Guaranteeing Subsidiaries, the
Subsidiary Guarantors and the Trustee
4.133
333-215288
Form S-1
(filed December 23, 2016)
4.1
—
Registration Rights Agreement, by and among TCEH Corp. (now
known as Vistra Corp.) and the Holders party thereto, dated as of
October 3, 2016
4.134
**
—
Description of Capital Stock
(10)
Material Contracts
Management Contracts; Compensatory Plans, Contracts and Arrangements
10.1
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.6
—
2016 Omnibus Incentive Plan
10.2
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.7
—
Form of Option Award Agreement (Management) for 2016
Omnibus Incentive Plan (pre-2021 awards)
10.3
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
10.5
—
Form of Option Award Agreement (Management) for 2016
Omnibus Incentive Plan
10.4
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
10.6
—
Form of Restricted Stock Unit Award Agreement (Management)
for 2016 Omnibus Incentive Plan (2021)
10.5
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
10.7
—
Form of Restricted Stock Unit Award Agreement (Director) for
2016 Omnibus Incentive Plan
10.6
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
10.8
—
Form of Performance Stock Unit Award Agreement for 2016
Omnibus Incentive Plan (2021)
10.7
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.9
—
Vistra Corp. Executive Annual Incentive Plan
10.8
**
—
Form of Restricted Stock Unit Award Agreement (Management),
for 2016 Omnibus Incentive Plan, effective as of January 1, 2025
10.9
**
—
Form of Performance Stock Unit Award Agreement (Management)
for 2016 Omnibus Incentive Plan, effective as of January 1, 2025
10.10
**
—
Amended and Restated Vistra Annual Incentive Plan, effective as of
January 1, 2025
Exhibits
Previously Filed With File
Number*
As
Exhibit
169

10.11
001-38086
Form 8-K
(filed on May 23, 2019)
10.1
—
Amended and Restated 2016 Omnibus Incentive Plan, effective as
of May 20, 2019
10.12
001-38086
Form of 8-K
(filed on May 6, 2024)
10.1
—
Amended and Restated 2016 Omnibus Incentive Plan effective as
of May 1, 2024
10.13
001-33443
Form10-K (Year ended
December 31, 2018) (filed
on February 28, 2019)
10.7
—
Vistra Equity Deferred Compensation Plan for Certain Directors,
effective as of January 1, 2019
10.14
001-38086
Form 10-K (Year ended
December 31, 2020) (filed
on February 26, 2021)
10.13
—
Amendment No. 1 to the Vistra Equity Deferred Compensation
Plan, dated effective as of February 24, 2021
10.15
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
10.15
—
Second Amended and Restated Employment Agreement, dated
March 20, 2022, between James A. Burke and Vistra Corp.
10.16
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
10.16
—
Employment Agreement, dated as of July 20, 2022, between
Kristopher E. Moldovan, Vistra Corp. and Vistra Corporate
Services Company
10.17
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
10.17
—
Amended and Restated Employment Agreement, dated as of May 5,
2022, between Stephanie Zapata Moore, Vistra Corp. and Vistra
Corporate Services Company
10.18
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
10.18
—
Amended and Restated Employment Agreement, dated as of May 5,
2022, between Carrie Lee Kirby, Vistra Corp. and Vistra Corporate
Services Company
10.19
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
10.19
—
Amended and Restated Employment Agreement, dated as of May 5,
2022, between Scott A. Hudson, Vistra Corp. and Vistra Corporate
Services Company
10.20
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
10.20
—
Amended and Restated Employment Agreement, dated as of May 5,
2022, between Stephen J. Muscato, Vistra Corp. and Vistra
Corporate Services Company
10.21
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
10.21
—
Employment Agreement, dated as of August 23, 2022, between
Stacey Doré, Vistra Corp. and Vistra Corporate Services Company
10.22
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
10.22
—
Form of indemnification agreement with directors and officers
Credit Agreements and Related Agreements
10.23
333-215288
Form S-1
(filed December 23, 2016)
10.1
—
Credit Agreement, dated as of October 3, 2016
10.24
333-215288
Form S-1
(filed December 23, 2016)
10.2
—
Amendment to Credit Agreement, dated December 14, 2016, by
and among Deutsche Bank AG New York Branch, Vistra
Operations Company LLC, Vistra Intermediate Company LLC and
the other Credit Parties and Lenders party thereto.
Exhibits
Previously Filed With File
Number*
As
Exhibit
170

10.25
333-215288
Amendment No. 1
to Form S-1
(filed February 14, 2017)
10.3
—
Second Amendment to Credit Agreement, dated February 1, 2017,
by and among Deutsche Bank AG New York Branch, Vistra
Operations Company LLC, Vistra Intermediate Company LLC and
the other Credit Parties and Lenders party thereto.
10.26
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.4
—
Third Amendment to Credit Agreement, dated February 28, 2017,
by and among Deutsche Bank AG New York Branch, Vistra
Operations Company LLC, Vistra Intermediate Company LLC and
the other Credit Parties and Lenders party thereto.
10.27
001-38086
Form 8-K
(filed August 17, 2017)
10.1
—
Fourth Amendment to Credit Agreement, dated as of August 17,
2017 (effective August 17, 2017), by and among Deutsche Bank
AG New York Branch, Vistra Operations Company LLC, Vistra
Intermediate Company LLC and the other Credit Parties and
Lenders party thereto.
10.28
001-38086
Form 8-K
(filed December 14, 2017)
10.1
—
Fifth Amendment to Credit Agreement, dated as of December 14,
2017 (effective December 14, 2017), by and among Deutsche Bank
AG New York Branch, Vistra Operations Company LLC, Vistra
Intermediate Company LLC and the other Credit Parties and
Lenders party thereto.
10.29
001-38086
Form 8-K
(filed February 22, 2018)
10.1
—
Sixth Amendment to Credit Agreement, dated as of February 20,
2018 (effective February 20, 2018), by and among Deutsche Bank
AG New York Branch, Vistra Operations Company LLC, Vistra
Intermediate Company LLC and the other Credit Parties and
Lenders party thereto.
10.30
001-38086
Form 8-K
(filed June 15, 2018)
10.1
—
Seventh Amendment to Credit Agreement, dated as of June 14,
2018, by and among Vistra Operations Company LLC, Vistra
Intermediate Company LLC, the other Credit Parties party thereto,
Credit Suisse and Citibank, N.A. as the 2018 Incremental Term
Loan Lenders, the various other Lenders party thereto, Credit
Suisse as Successor Administrative Agent and as Successor
Collateral Agent, and Delaware Trust Company, as Collateral
Trustee.
10.31
001-38086
Form 8-K
(filed April 4, 2019)
10.4
—
Eighth Amendment to Credit Agreement, dated March 29, 2019, by
and among Vistra Operations Company LLC, Vistra Intermediate
Company LLC, the other Credit Parties (as defined in the Vistra
Operations Credit Agreement) party thereto, Bank of Montreal,
Chicago Branch, as new Revolving Loan Lender, Revolving Letter
of Credit Issuer and Joint Lead Arranger, the various other Lenders
and Letter of Credit Issuers party thereto, and Credit Suisse as
Administrative Agent and Collateral Agent
10.32
001-38086
Form 8-K
(filed May 29, 2019)
10.1
—
Ninth Amendment to Credit Agreement, dated May 29, 2019, by
and among Vistra Operations Company LLC, Vistra Intermediate
Company LLC, the other Credit Parties (as defined in the Vistra
Operations Credit Agreement) party thereto, Sun Trust Bank, as
incremental Revolving Loan Lender, and Credit Suisse AG,
Cayman Island Branch, as Administrative Agent and Collateral
Agent
10.33
001-38086
Form 8-K (filed
on November 21, 2019)
10.1
—
Tenth Amendment to the Credit Agreement, dated November 15,
2019, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
other Credit Parties (as defined in the Credit Agreement) party
thereto, the other Credit Parties (as defined in the Credit
Agreement) party thereto, Credit Suisse AG, Cayman Islands
Branch (as the 2019 Incremental Term Loan Lender and as
Administrative Agent and as Collateral Agent), and the other
Lenders party thereto
Exhibits
Previously Filed With File
Number*
As
Exhibit
171

10.34
001-38086
Form 8-K (filed
on May 5, 2022)
10.1
—
Eleventh Amendment to the Credit Agreement, dated April 29,
2022, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
other Credit Parties (as defined in the Credit Agreement) party
thereto, the other Credit Parties (as defined in the Credit
Agreement) party thereto, the financial institutions providing 2022
New Revolving Credit Commitments (as defined in the Credit
Agreement),
the
Revolving
Credit
Lenders
providing
2022
Extended Revolving Credit Commitments (as defined in the Credit
Agreement), the Revolving Letter of Credit Issuers (as defined in
the Credit Agreement) party thereto, and Credit Suisse AG,
Cayman Islands Branch (as Administrative Agent and as Collateral
Agent)
10.35
001-38086
Form 10-Q (Quarter ended
September 30, 2022) (filed
on November 4, 2022)
10.3
—
Twelfth Amendment to the Credit Agreement, dated July 18, 2022,
by and among Vistra Operations Company LLC (as Borrower),
Vistra Intermediate Company LLC (as Holdings), the other Credit
Parties (as defined in the Credit Agreement) party thereto, financial
institutions, Revolving Credit Lenders, and Revolving Letter of
Credit Issuers (in each case as defined in the Credit Agreement)
party thereto, and Credit Suisse AG, Cayman Islands Branch (as
Administrative Agent and as Collateral Agent)
10.36
001-38086
Form 10-Q (Quarter ended
June 30, 2023) (filed on
August 9, 2023)
10.1
—
Thirteenth Amendment to the Credit Agreement, dated April 28,
2023, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
other Credit Parties (as defined in the Credit Agreement) party
thereto, financial institutions, Revolving Credit Lenders, and
Revolving Letter of Credit Issuers (in each case as defined in the
Credit Agreement) party thereto, and Credit Suisse AG, Cayman
Islands Branch (as Administrative Agent and as Collateral Agent)
10.37
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
10.1
—
Fourteenth Amendment to the Credit Agreement, dated September
26, 2023, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
other Credit Parties (as defined in the Credit Agreement) party
thereto, financial institutions, Revolving Credit Lenders, and
Revolving Letter of Credit Issuers (in each case as defined in the
Credit Agreement) party thereto, and Credit Suisse AG, Cayman
Islands Branch (as Administrative Agent and as Collateral Agent)
10.38
001-38086
Form 8-K (filed
on December 26, 2023)
10.1
—
Fifteenth Amendment to the Credit Agreement, dated December 20,
2023, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
2023 Incremental Term Loan Lender, the other Credit Parties (as
defined in the Credit Agreement) party thereto, the other lenders
party thereto, and Credit Suisse AG, Cayman Islands Branch (as
Administrative Agent and as Collateral Agent)
10.39
001-38086
Form 10-Q (Quarter ended
September 30, 2024) (filed
on November 8, 2024)
10.6
—
Sixteenth Amendment to the Credit Agreement, dated October 11,
2024, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
guarantors party thereto, the revolving credit lenders and revolving
letter of credit issuers party thereto, and Citibank, N.A. (as
Administrative Agent and as Collateral Agent)
10.40
001-38086
Form 8-K
(filed on December 16,
2024)
10.1
—
Seventeenth Amendment to Credit Agreement, dated December 10,
2024, by and among Vistra Operations Company LLC (as
Borrower), Vistra Intermediate Company LLC (as Holdings), the
other Credit Parties (as defined in the Credit Agreement) party
thereto,
the
lenders
party
thereto,
and
Citibank,
N.A.
(as
Administrative Agent and Collateral Agent)
10.41
001-38086
Form 8-K
(filed on April 9, 2018)
10.10
—
Assumption Agreement, dated as of April 9, 2018, between Vistra
Energy Corp. (now known as Vistra Corp.) (as successor by merger
to Dynegy Inc.), and Credit Suisse AG, Cayman Islands Branch, as
Administrative Agent and as Collateral Trustee.
Exhibits
Previously Filed With File
Number*
As
Exhibit
172

10.42
001-38086
Form 8-K
(filed on April 9, 2018)
10.11
—
Guarantee and Collateral Agreement, dated as of April 23, 2013,
among Dynegy Inc., the subsidiaries of the borrower from time to
time party thereto and Credit Suisse AG, Cayman Islands Branch,
as Collateral Trustee (incorporated by reference to Exhibit 10.2 to
the Current Report on Form 8-K of Dynegy Inc. filed on April 24,
2013).
10.43
001-38086
Form 8-K
(filed on April 9, 2018)
10.12
—
Joinder, dated as of April 9, 2018, among Vistra Energy Corp. (now
known as Vistra Corp.), the subsidiary guarantors party thereto and
Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee.
10.44
001-38086
Form 8-K
(filed on April 9, 2018)
10.13
—
Collateral Trust and Intercreditor Agreement, dated as of April 23,
2013 among Dynegy, the Subsidiary Guarantors (as defined
therein), Credit Suisse AG, Cayman Islands Branch and each
person party thereto from time to time (incorporated by reference to
Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc.
filed on April 24, 2013).
10.45
001-38086
Form 10-K (Year ended
December 31, 2021) (filed
on February 25, 2022)
10.63
—
Credit Agreement, dated as of February 4, 2022, among Vistra
Operations Company LLC, as Borrower, Vistra Intermediate
Company LLC, as Holdings, Citibank, N.A., as Administrative
Agent and as Collateral Agent, and the other lenders party thereto
10.46
001-38086
Form 10-Q (Quarter ended
June 30, 2022) (filed on
August 5, 2022)
10.3
—
First Amendment to Credit Agreement, dated as of May 5, 2022,
among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
10.47
001-38086
Form 10-Q (Quarter ended
June 30, 2022) (filed on
August 5, 2022)
10.4
—
Second Amendment to Credit Agreement, dated as of May 26,
2022, among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
10.48
001-38086
Form 10-Q (Quarter ended
June 30, 2022) (filed on
August 5, 2022)
10.5
—
Third Amendment to Credit Agreement, dated as of June 8, 2022,
among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
10.49
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
10.72
—
Fourth Amendment to Credit Agreement, dated as of October 5,
2022, among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
10.50
001-38086
Form 10-K (Year ended
December 31, 2022) (filed
on March 1, 2023)
10.73
—
Fifth Amendment to Credit Agreement, dated as of October 21,
2022, among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
10.51
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
10.2
—
Sixth Amendment to Credit Agreement, dated as of September 26,
2023, among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
10.52
001-38086
Form 10-Q (Quarter ended
September 30, 2023) (filed
on November 7, 2023)
10.3
—
Seventh Amendment to Credit Agreement, dated as of October 4,
2023, among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
Exhibits
Previously Filed With File
Number*
As
Exhibit
173

10.53
001-38086
Form 10-Q (Quarter ended
September 30, 2024) (filed
on November 8, 2024)
10.5
—
Eighth Amendment to Credit Agreement, dated as of October 2,
2024, among Vistra Operations Company LLC, as Borrower, Vistra
Intermediate Company LLC, as Holdings, Citibank, N.A., as
Administrative Agent and as Collateral Agent, and the other lenders
party thereto
10.54
001-38086
Form 8-K
(filed on April 1, 2024)
10.1
—
Credit Agreement, dated March 26, 2024, by and among Vistra
Zero Operating Company, LLC, the Lenders (as defined in the
Credit
Agreement)
party
thereto
and
Citibank,
N.A.
(as
Administrative Agent and as Collateral Agent)
10.55
001-38086
Form 8-K
(filed on December 19,
2024)
10.1
—
First Amendment to Credit Agreement, dated December 17, 2024,
by and among Vistra Zero Operating Company, LLC, the
guarantors party thereto, the lenders party thereto and Citibank,
N.A. (as Administrative Agent and Collateral Agent)
Other Material Contracts
10.56
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.5
—
Collateral Trust Agreement, dated as of October 3, 2016, by and
among TEX Operations Company LLC (now known as Vistra
Operations LLC), the Grantors from time to time thereto, Railroad
Commission of Texas, as first-out representative, and Deutsche
Bank
AG,
New
York
Branch,
as
senior
credit
agreement
representative
10.57
001-38086
Form 8-K
(filed on June 15, 2018)
10.2
—
Amendment to Collateral Trust Agreement, effective as of June 14,
2018, among Vistra Operations Company LLC, the other Grantors
from time to time party thereto, Railroad Commission of Texas, as
first-out representative, and Credit Suisse AG, Cayman Islands
Branch, as senior credit agreement agent, and Delaware Trust
Company, as Collateral Trustee
10.58
001-38086
Form 8-K
(filed on June 15, 2018)
10.3
—
Collateral Trust Joinder, dated June
14, 2018, between the
Additional Grantors party thereto and Delaware Trust Company, as
Collateral Trustee, to the Collateral Trust Agreement, effective
pursuant to the Seventh Amendment as of June 14, 2018, among
Vistra Operations Company LLC, the other Grantors from time to
time party thereto, Railroad Commission of Texas, as First-Out
Representative, Credit Suisse AG, Cayman Islands Branch, as
Senior Credit Agreement Agent, and Delaware Trust Company, as
Collateral Trustee.
10.59
001-38086
Form 8-K
(filed on January 4, 2024)
10.1
—
Amended
and
Restated
Tax
Receivable
Agreement,
dated
December 29, 2023, by and between the Company and Equiniti
Trust Company, LLC
10.60
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.14
—
Tax Matters Agreement, by and among TEX Energy LLC (now
known as Vistra Corp.), EFH Corp., Energy Future Intermediate
Holding Company LLC, EFI Finance Inc. and EFH Merger Co.
LLC, dated as of October 3, 2016
10.61
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.18
—
Amended and Restated Split Participant Agreement, by and
between Oncor Electric Delivery Company LLC (f/k/a TXU
Electric Delivery Company) and TEX Operations Company LLC
(now known as Vistra Operations Company LLC), dated as of
October 3, 2016
10.62
001-38086
Form 8-K
(filed on October 16, 2020)
10.1
—
Master Framework Agreement, dated as of October 9, 2020, by and
among TXU Energy Retail Company LLC, as seller and seller party
agent, certain originators named therein, and MUFG Bank, Ltd., as
buyer
10.63
001-38086
Form 8-K
(filed on July 15, 2021)
10.1
—
Amendment No. 1 to Master Framework Agreement, dated as of
July 1, 2021, by and among TXU Energy Retail Company LLC, as
seller and seller party agent, certain originators named therein,
Vistra Operations Company LLC, as guarantor, and MUFG Bank,
Ltd., as buyer
Exhibits
Previously Filed With File
Number*
As
Exhibit
174

10.64
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
10.2
—
Amendment No. 2 to Master Framework Agreement, dated as of
August 3, 2021, by and among TXU Energy Retail Company LLC,
as seller and seller party agent, certain originators named therein,
Vistra Operations Company LLC, as guarantor, and MUFG Bank,
Ltd., as buyer
10.65
001-38086
Form 8-K
(filed on July 15, 2022)
10.1
—
Amendment No. 3 to Master Framework Agreement, dated as of
July 11, 2022, by and among TXU Energy Retail Company LLC, as
seller and seller party agent, certain originators named therein,
Vistra Operations Company LLC, as guarantor, and MUFG Bank,
Ltd., as buyer
10.66
001-38086
Form 8-K
(filed on July 17, 2023)
10.1
—
Amendment No. 4 to Master Framework Agreement, dated as of
July 11, 2023, by and among TXU Energy Retail Company LLC, as
seller and seller party agent, certain originators name therein, Vistra
Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as
buyer
10.67
001-38086
Form 8-K
(filed on July 12, 2024)
10.1
—
Amendment No. 5 to Master Framework Agreement, dated as of
July 11, 2024, by and among TXU Energy Retail Company LLC, as
seller and seller party agent, certain originators name therein, Vistra
Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as
buyer
10.68
001-38086
Form 8-K
(filed on October 16, 2020)
10.2
—
Master Repurchase Agreement, dated as of October 9, 2020,
between TXU Energy Retail Company LLC and MUFG Bank, Ltd.
10.69
001-38086
Form 10-Q (Quarter ended
September 30, 2021) (filed
on November 5, 2021)
10.3
—
Amendment No. 1 to Master Repurchase Agreement, dated as of
August 3, 2021, between TXU Energy Retail Company LLC and
MUFG Bank, Ltd.
10.70
001-38086
Form 8-K
(filed on December 28,
2020)
10.1
—
Joinder Agreement, dated as of December 21, 2020, among TXU
Energy Retail company LLC, as seller party agent, Vistra
Operations Company LLC, as guarantor, certain originators named
therein, and MUFG Bank, Ltd., as buyer
10.71
001-38086
Form 10-K (Year ended
December 31, 2021) (filed
on February 25, 2022)
10.62
—
Amendment No. 2 to Master Repurchase Agreement, dated as of
December 30, 2021, between TXU Energy Retail Company LLC
and MUFG Bank, Ltd.
10.72
001-38086
Form 8-K
(filed on July 17, 2023)
10.2
—
Amendment No. 3 to Master Repurchase Agreement, dated as of
July 11, 2023, by and among TXU Energy Retail Company LLC, as
seller and MUFG Bank, Ltd., as buyer
10.73
001-38086
Form 8-K
(filed on April 9, 2024)
10.1
—
Joinder Agreement, dated as of April 8, 2024, among TXU Retail,
as seller party agent, Vistra Operations, as guarantor, certain
originators named therein, and MUFG, as buyer
10.74
001-38086
Form 8-K
(filed on July 12, 2024)
10.2
—
Amendment No. 4 to Master Repurchase Agreement, dated as of
July 11, 2024, by and among TXU Energy Retail Company LLC, as
seller and MUFG Bank, Ltd., as buyer
10.75
001-38086
Form 8-K
(filed on November 19,
2024)
10.1
—
Letter Agreement, dated November 17, 2024, by and among Vistra
Operations Company LLC, Vistra Vision Holdings I LLC, and VV
Aggregator Holdings 1 LLC
10.76
**
—
Amended and Restated Class B Unit Purchase Agreement, dated
December 11, 2024, by and among Vistra Operations Company
LLC,
Vistra
Vision
Holdings
I
LLC,
and
Nuveen
Asset
Management, LLC
(19)
Insider Trading Policy
19.1
**
—
Transactions in Vistra Corp. Securities Policy
Exhibits
Previously Filed With File
Number*
As
Exhibit
175

(21)
Subsidiaries of the Registrant
21.1
**
—
Significant Subsidiaries of Vistra Corp.
(23)
Consent of Experts
23.1
**
—
Consent of Deloitte & Touche LLP
(31)
Rule 13a-14(a) / 15d-14(a) Certifications
31.1
**
—
Certification of James A. Burke, principal executive officer of
Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
31.2
**
—
Certification of Kristopher E. Moldovan, principal financial officer
of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002
(32)
Section 1350 Certifications
32.1
***
—
Certification of James A. Burke, principal executive officer of
Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
32.2
***
—
Certification of Kristopher E. Moldovan, principal financial officer
of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(95)
Mine Safety Disclosures
95.1
**
—
Mine Safety Disclosures
(97)
Policy Relating to Recover of Erroneously Awarded Compensation
97.1
001-38086
Form 10-K (Year ended
December 31, 2023) (filed
on February 29, 2024)
97.1
—
Vistra Corp. Clawback Policy
XBRL Data Files
101.INS
**
—
The following financial information from Vistra Corp.'s Annual
Report on Form 10-K for the period ended December 31, 2024
formatted
in
Inline
XBRL
(Extensible
Business
Reporting
Language) includes: (i) the Consolidated Statements of Operations,
(ii) the Consolidated Statements of Comprehensive Income (Loss),
(iii) the
Consolidated Statements of Cash Flows, (iv) the
Consolidated Balance Sheets, (v) the Consolidated Statement of
Changes in Equity and (vi) the Notes to the Consolidated Financial
Statements.
101.SCH
**
—
XBRL Taxonomy Extension Schema Document
101.CAL
**
—
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
**
—
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
**
—
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
**
—
XBRL Taxonomy Extension Presentation Linkbase Document
104
—
The Cover Page Interactive Data File does not appear in Exhibit
104 because its XBRL tags are embedded within the Inline XBRL
document.
Exhibits
Previously Filed With File
Number*
As
Exhibit
____________________
*
Incorporated herein by reference
**
Filed herewith
*** Furnished herewith
176

Item 16.
FORM 10-K SUMMARY
None.
177

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Vistra Corp. has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
VISTRA CORP.
Date: February 27, 2025
By
/s/ JAMES A. BURKE
James A. Burke (President and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of Vistra Corp. and in the capacities and on the date indicated.
/s/ JAMES A. BURKE
Principal Executive Officer
and Director
February 27, 2025
(James A. Burke, President and Chief Executive Officer)
/s/ KRISTOPHER E. MOLDOVAN
Principal Financial Officer
February 27, 2025
(Kristopher E. Moldovan, Chief Financial Officer)
/s/ MARGARET MONTEMAYOR
Principal Accounting Officer
February 27, 2025
(Margaret Montemayor, Senior Vice President, Chief Accountant and
Controller)
/s/ SCOTT B. HELM
Chairman of the Board and
Director
February 27, 2025
(Scott B. Helm, Chairman of the Board)
/s/ HILARY E. ACKERMANN
Director
February 27, 2025
(Hilary E. Ackermann)
/s/ ARCILIA C. ACOSTA
Director
February 27, 2025
(Arcilia C. Acosta)
/s/ GAVIN R. BAIERA
Director
February 27, 2025
(Gavin R. Baiera)
/s/ PAUL M. BARBAS
Director
February 27, 2025
(Paul M. Barbas)
/s/ LISA CRUTCHFIELD
Director
February 27, 2025
(Lisa Crutchfield)
/s/ JULIE A. LAGACY
Director
February 27, 2025
(Julie A. Lagacy)
/s/ JOHN W. PITESA
Director
February 27, 2025
(John W. Pitesa)
/s/ JOHN R. SULT
Director
February 27, 2025
(John R. Sult)
/s/ ROBERT C. WALTERS
Director
February 27, 2025
(Robert C. Walters)
Signature
Title
Date
178

Stock Exchange Listing
NYSE: VST
Corporate Headquarters
Vistra Corp.
6555 Sierra Drive
Irving, Texas 75039
Stock Transfer Agent and
Registrar
Please direct general questions
about stockholder accounts, stock
certificates, transfer of shares, or
duplicate mailings to Vistra’s
transfer agent:
Equiniti Trust Company, LLC
6201 15th Avenue
Brooklyn, NY 11219
Phone: (800) 937-5449
(718) 921-8124
Email: HelpAST@equiniti.com
Independent Registered
Accounting Firm
Deloitte & Touche LLP
Officer Certifications
Our Annual Report on Form 10-K
filed with the SEC is included
herein, excluding all exhibits. We
will send stockholders copies of
the exhibits to our Annual Report
on Form 10-K and any of our
corporate governance documents,
free of charge, upon request.
Note that these documents, along
with further information about our
company, board of directors,
management team and investor
relations contact details, are
available on our website at www.
vistracorp.com.
Board of Directors †
Hilary E. Ackermann (4*,5)
Arcilia C. Acosta (1,3)
Gavin R. Baiera (2,4)
Paul M. Barbas (1,3,5)
Jim Burke
Lisa Crutchfield (2*)
Scott B. Helm,
Chairman of the Board of
Directors
Julie A. Lagacy (3*,4)
John W. (Bill) Pitesa (2,5*)
John R. (J. R.) Sult (1*)
Robert C. Walters (3,4)
STOCKHOLDER INFORMATION
1 Audit Committee
2 Social Responsibility
and Compensation Committee
3 Nominating and Governance Committee
4 Sustainability and Risk Committee
5 Generation and Safety Oversight Committee
* Committee Chair
† As of March 19, 2025, besides Jim Burke, all
members of the Vistra Board of Directors satisfy
the independence requirements of the Securities
and Exchange Commission and the NYSE.

6555 Sierra Drive, Irving, Texas 75039 I www.vistracorp.com