Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion below, as well as other portions of this quarterly report on Form 10-Q, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995. In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC. Readers can usually identify these forward-looking statements by the use of such words as “may,” “will,” “should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words. These statements involve a number of risks and uncertainties. Actual results could materially differ from those anticipated by such forward-looking statements. For more discussion about risk factors that could cause or contribute to such differences, see Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and Part I, Item 1A "Risk Factors" in the Company’s 2020 Form 10-K and any updates contained herein. Forward-looking statements reflect the information only as of the date on which they are made. The Company does not undertake any obligation to update any forward-looking statements to reflect future events, developments, or other information. If Vistra does update one or more forward-looking statements, no inference should be drawn that additional updates will be made regarding that statement or any other forward-looking statements. This discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity, capital structure and business developments for the periods covered by the consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q for the three and nine months ended September 30, 2021. This discussion should be read in conjunction with those consolidated financial statements and the related notes and is qualified by reference to them.

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2021 and 2020 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements.

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

Critical Accounting Policies and Estimates

The Company's discussion and analysis of its financial position and results of operations is based upon its consolidated financial statements. The preparation of these consolidated financial statements requires estimation and judgment that affect the reported amounts of revenue, expenses, assets and liabilities. The Company bases its estimates on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the accounting for assets and liabilities that are not readily apparent from other sources. If the estimates differ materially from actual results, the impact on the consolidated financial statements may be material. The Company's critical accounting policies are disclosed in our 2020 Form 10-K.

Business

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

Operating Segments

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

Significant Activities and Events and Items Influencing Future Performance

Winter Storm Uri

In February 2021, the U.S. experienced an unprecedented Winter Storm Uri, bringing extreme cold temperatures to the central U.S., including Texas. On February 12, 2021, the Governor of Texas declared a state of disaster for all 254 counties in the State in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide. On February 14, 2021, President Biden issued a federal emergency declaration for all 254 Texas counties.

As part of its annual winter season preparations, our power plant teams executed a significant winter preparedness strategy, which included installing windbreaks and large radiant heaters to supplement existing freeze protection and insulation and performing preventative maintenance on freeze protection equipment such as the insulation and automatic circuitry designed to keep pipes at the power plants from freezing. In addition, in anticipation of Winter Storm Uri we took additional steps to prepare, including procuring additional demineralized water supply trailers to ensure sufficient water availability to run for extended periods and verifying that freeze protection circuits were operational.

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

The weather event resulted in a $2.9 billion negative impact on the Company's pre-tax earnings in the nine months ended September 30, 2021 (see Note 1 to the Financial Statements). The primary drivers of the loss were the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs.

The final amount of the storm impact is subject to legislative actions that may be taken, such as legislation passed in the Texas Legislature's 87th Session. Securitization bills SB 1580 and HB 1520 may impact the total amount of balances owed by electric cooperatives to the market. The PUCT is required to issue financing orders related to those bills that authorizes financing associated with this legislation to defaulting market participants. The potential impact of this legislation is subject to uncertainty as the final details associated with the securitization bills will be determined through the potential approval of the financing orders.

In September 2021, the PUCT approved a settlement agreement among ERCOT, PUCT staff and certain ERCOT market participants who are parties to the PUCT proceeding in which ERCOT has applied for an order to finance, administer and distribute to eligible ERCOT market participants the securitization provided for under Texas House Bill 4492 (HB 4492). HB 4492 authorizes ERCOT to securitize up to $2.1 billion of certain costs allocated by ERCOT to load-serving entities (LSEs) during Winter Storm Uri. HB 4492, and final terms related thereto, are subject to the final financing order issued in October 2021, together with ERCOT obtaining sufficient financing related thereto. Though the final allocations will be determined following the completion of an administrative process, including final determination of which LSEs will participate in or opt out of the program, we expect to receive approximately $500 million of proceeds.

In addition, the final amount of the storm impact continues to be subject to the outcome of potential litigation arising from this event (including any litigation that we may pursue or be a party to); or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain that is currently being considered or may be considered by any such parties. There have already been several announced efforts by the state and federal governments and regulatory agencies to investigate and determine the causes of this event and its impact on consumers. We have received a civil investigative demand from the Attorney General of Texas as well as requests for information from ERCOT related to this event and may receive additional inquiries. We are cooperating with these entities and are working to respond to these requests. Those efforts may result in changes in regulations that impact our industry 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 and natural gas supply chains during any future event; potential revisions to the way in which the ERCOT market compensates and incentivizes the continued operation of assets that only run during times of scarcity; and potential changes to the types of plans permitted to be marketed to residential customers. We are continuing to monitor this situation as it develops. The full impact of litigation or any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event could have a material impact on our business, financial condition, results of operations, or cash flows, but cannot be estimated at this time. See Note 11 to the Financial Statements for further discussion of these matters.

The fundamentals of the Company remain strong. As described under Available Liquidity, the Company has total available liquidity of $2.071 billion as of September 30, 2021, consisting of cash on hand and available capacity under our Revolving Credit Facility. In addition, the maturities of our long-term debt are relatively modest until 2023. If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, such as a result of Winter Storm Uri, the Company believes it would have additional alternatives to maintain access to liquidity, including drawing upon available liquidity, accessing additional sources of capital or reducing capital expenditures, planned voluntary debt repayments or operating costs.

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

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

Investments in Clean Energy and CO2 Reductions

In September 2021, we announced the planned development, at a cost of approximately $550 million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act. In September 2020, we announced the planned development, at a cost of approximately $850 million, of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. We will only invest in these growth projects if we are confident in the expected returns. See Note 2 to the Financial Statements for a summary of our solar and battery energy storage projects.

In September 2020 and December 2020, we announced our intention to retire (a) all of our remaining coal generation facilities in Illinois and Ohio, (b) one coal generation facility in Texas and (c) two natural gas facilities in Illinois and Texas no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 11 to the Financial Statements), and in furtherance of our efforts to significantly reduce our carbon footprint. In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022, and in July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022. See Note 3 to the Financial Statements for a summary of these planned generation retirements.

Moss Landing Phase I Outage

On September 4, 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. An initial review has found that only a small, single digit-percentage of batteries at the facility were impacted. The facility will be offline as the company continues to safely advance its root cause analysis and perform the work necessary to return the facility to service. We do not currently have an estimated return to service date for the facility. Moss Landing Phase II was not affected and remains operational. We do not expect the incident to have a material impact on our results of operations.

Mining Reclamation Award

On October 14, 2021, the Office of Surface Mining Reclamation and Enforcement (OSM) announced Luminant as a recipient of its 2021 Excellence in Surface Coal Mining Reclamation Award for the work done to reclaim and restore previously mined land at its Monticello-Winfield Mine. The award recognizes companies that achieve the most exemplary coal mine reclamation in the nation. Luminant has a long history of environmental stewardship, reclaiming land long before being required under federal or state law.

COVID-19 Pandemic

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

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

See Note 6 to the Financial Statements for a summary of certain tax-related impacts of the CARES Act to the Company.

The COVID-19 pandemic has presented potential new risks to the Company's business. Although there have been logistical and other challenges to date, there has been no material adverse impact on the Company's nine months ended September 30, 2021 results of operations. The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company's results of operations, financial condition and liquidity increases the longer the virus impacts the level of economic activity in the U.S. and globally. As a result, COVID-19 may have a range of impacts on the Company's operations, the full extent and scope of which are currently unknown. See Part I, Item 1A Risk Factors — The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, and results of operations in our 2020 Form 10-K.

Dividend Program

In November 2018, we announced that the Board had adopted a dividend program, which we initiated in the first quarter of 2019. See Note 12 to the Financial Statements for more information about our dividend program.

Series A Preferred Stock Offering

On October 15, 2021, we issued of 1,000,000 shares of Series A Preferred Stock in a private offering (Offering). The net proceeds of the Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (discussed below). See Note 12 to the Financial Statements for more information concerning the Series A Preferred Stock.

Share Repurchase Program

In October 2021, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2012. The Share Repurchase Program supersedes the $1.5 billion share repurchase program previously announced in September 2020 (Prior Share Repurchase Program). We intend to use the net proceeds from the Preferred Stock Offering to repurchase shares of our outstanding common stock. We expect to complete repurchases under the Share Repurchase Program by the end of 2022. See Note 12 to the Financial Statements for more information concerning the Share Repurchase Program and the Prior Share Repurchase Program, including shares repurchased.

Debt Activity

We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize our capital structure, maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities and/or reduce ongoing interest expense. While the financial impacts resulting from Winter Storm Uri caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet. See Note 10 to the Financial Statements for details of our long-term debt activity and Note 9 to the Financial Statements for details of our accounts receivable financing.

Power Price, Natural Gas Price and Market Heat Rate Exposure

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments at September 30, 2021 were as follows:


	2021		2022
Nuclear/Renewable/Coal Generation:
Texas	97	%	85	%
Sunset	100	%	93	%
Gas Generation:
Texas	89	%	53	%
East	98	%	89	%
West	100	%	92	%

The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed heat rate of 7.2 MMBtu/MWh) on realized pre-tax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of September 30, 2021.


	Balance 2021		2022
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	1	$	18
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	(1)	$	(18)
Gas Generation: $1.00/MWh increase in spark spread	$	1	$	20
Gas Generation: $1.00/MWh decrease in spark spread	$	(1)	$	(18)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	(22)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	15
East:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	6
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(4)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	(3)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	3
West:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	1
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	—


Sunset:
Coal Generation: $2.50/MWh increase in power price	$	—	$	7
Coal Generation: $2.50/MWh decrease in power price	$	—	$	(5)

PJM Auction Results

In June 2021, Vistra reported its results from PJM's Reliability Pricing Model (RPM) auction results for planning year 2022-2023, and the table below lists clearing price per MW-day and our cleared capacity volumes by zone:


	Clearing Price per MW-day		East Segment MW Cleared	Sunset Segment MW Cleared	Total MW Cleared
RTO zone	$	50.00	2,967	—	2,967
ComEd zone	$	68.96	1,255	649	1,904
DEOK zone	$	71.69	99	870	969
MAAC zone	$	95.79	548	—	548
EMAAC zone	$	97.86	831	—	831
ATSI zone	$	50.00	—	—	—
Total	$	66.90	5,700	1,519	7,219

Our capacity sales in PJM, net of purchases, for planning year 2022-2023, are as follows:


	East Segment		Sunset Segment		Total
Total capacity sold, net (MW)	5,700		1,519		7,219


Average price per MW-day	$	68.54	$	70.52	$	68.95

RESULTS OF OPERATIONS

Consolidated Financial Results — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) $ Change			Nine Months Ended September 30,					Favorable (Unfavorable) $ Change
	2021		2020				2021			2020
Operating revenues	$	2,991	$	3,552	$	(561)		$	8,763		$	8,919	$	(156)
Fuel, purchased power costs and delivery fees	(1,763)		(1,469)		(294)			(7,827)			(3,832)		(3,995)
Operating costs	(372)		(457)		85			(1,173)			(1,249)		76
Depreciation and amortization	(468)		(410)		(58)			(1,355)			(1,284)		(71)
Selling, general and administrative expenses	(269)		(268)		(1)			(771)			(755)		(16)

Impairment of long-lived assets	—		(272)		272			(38)			(356)		318
Operating income (loss)	119		676		(557)			(2,401)			1,443		(3,844)
Other income	16		8		8			108			19		89
Other deductions	(5)		—		(5)			(13)			(35)		22
Interest expense and related charges	(124)		(101)		(23)			(288)			(541)		253
Impacts of Tax Receivable Agreement	35		58		(23)			31			44		(13)
Equity in earnings of unconsolidated investment	—		—		—			—			4		(4)
Income (loss) before income taxes	41		641		(600)			(2,563)			934		(3,497)
Income tax (expense) benefit	(31)		(199)		168			569			(283)		852
Net income (loss)	$	10	$	442	$	(432)		$	(1,994)		$	651	$	(2,645)


	Three Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,160	$	843	$	508	$	90	$	(122)	$	—	$	(488)	$	2,991
Fuel, purchased power costs and delivery fees	(1,095)		(482)		(496)		(78)		(100)		—		488		(1,763)
Operating costs	(38)		(163)		(57)		(9)		(104)		(1)		—		(372)
Depreciation and amortization	(53)		(179)		(164)		(15)		(40)		—		(17)		(468)
Selling, general and administrative expenses	(192)		(23)		(19)		(7)		(14)		(5)		(9)		(269)


Operating income (loss)	782		(4)		(228)		(19)		(380)		(6)		(26)		119
Other income	1		7		—		—		7		1		—		16
Other deductions	—		(2)		—		—		(1)		—		(2)		(5)
Interest expense and related charges	(2)		3		(5)		1		(1)		(1)		(119)		(124)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		35		35

Income (loss) before income taxes	781		4		(233)		(18)		(375)		(6)		(112)		41
Income tax expense	(2)		—		—		—		—		—		(29)		(31)
Net income (loss)	$	779	$	4	$	(233)	$	(18)	$	(375)	$	(6)	$	(141)	$	10


	Three Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,521	$	1,541	$	644	$	84	$	299	$	1	$	(1,538)	$	3,552
Fuel, purchased power costs and delivery fees	(2,119)		(328)		(295)		(38)		(227)		—		1,538		(1,469)
Operating costs	(35)		(180)		(54)		(8)		(133)		(47)		—		(457)
Depreciation and amortization	(67)		(107)		(181)		(5)		(22)		(11)		(17)		(410)
Selling, general and administrative expenses	(190)		(18)		(12)		(8)		(15)		(8)		(17)		(268)

Impairment of long-lived assets	—		—		—		—		(272)		—		—		(272)
Operating income (loss)	110		908		102		25		(370)		(65)		(34)		676
Other income	1		1		—		1		—		5		—		8
Other deductions	—		(3)		—		—		3		—		—		—
Interest expense and related charges	(2)		2		(2)		3		(1)		—		(101)		(101)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		58		58

Income (loss) before income taxes	109		908		100		29		(368)		(60)		(77)		641
Income tax expense	—		—		—		—		—		—		(199)		(199)
Net income (loss)	$	109	$	908	$	100	$	29	$	(368)	$	(60)	$	(276)	$	442

In the three months ended September 30, 2021, 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 during a period of mild weather. Our performance reflected the stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business, to produce results in line with management's expectations.

Consolidated results decreased $557 million to operating income of $119 million in the three months ended September 30, 2021 compared to the three months ended September 30, 2020. The change in results is driven by $589 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $321 million in pre-tax unrealized gains on commodity heading transactions in 2020, partially offset by a $272 million impairment of long-lived assets related to our Kincaid and Zimmer generation facilities in 2020 (see Note 17 to the Financial Statements). Power, natural gas and coal forward market curves moved up during the three months ended September 30, 2021, driving these net pre-tax unrealized losses on commodity hedging transactions.

Depreciation expense for the three months ended September 30, 2021 includes a $45 million immaterial out-of-period adjustment to correct for the net understatement of depreciation expense related to prior periods. See Note 1 to the Financial Statements.

Interest expense and related charges increased $23 million to $124 million in the three months ended September 30, 2021 compared to the three months ended September 30, 2020 driven by $11 million higher interest paid/accrued and a $6 million debt extinguishment gain in 2020. See Note 17 to the Financial Statements.

For the three months ended September 30, 2021 and 2020, the Impacts of the Tax Receivable Agreement totaled income of $35 million and $58 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the three months ended September 30, 2021, income tax expense totaled $31 million and the effective tax rate was 75.6%. For the three months ended September 30, 2020, income tax expense totaled $199 million and the effective tax rate was 31.0%. See Note 6 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.


	Nine Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	5,829	$	1,458	$	1,738	$	171	$	109	$	—	$	(542)	$	8,763
Fuel, purchased power costs and delivery fees	(2,345)		(4,133)		(1,269)		(164)		(458)		—		542		(7,827)
Operating costs	(96)		(527)		(181)		(26)		(323)		(19)		(1)		(1,173)
Depreciation and amortization	(160)		(462)		(553)		(30)		(99)		—		(51)		(1,355)
Selling, general and administrative expenses	(539)		(62)		(56)		(22)		(42)		(20)		(30)		(771)

Impairment of long-lived assets	—		—		—		—		(38)		—		—		(38)
Operating income (loss)	2,689		(3,726)		(321)		(71)		(851)		(39)		(82)		(2,401)
Other income	1		72		—		—		11		20		4		108
Other deductions	(4)		(7)		—		—		—		—		(2)		(13)
Interest expense and related charges	(7)		10		(11)		9		(1)		(1)		(287)		(288)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		31		31

Income (loss) before income taxes	2,679		(3,651)		(332)		(62)		(841)		(20)		(336)		(2,563)
Income tax (expense) benefit	(2)		—		—		—		—		—		571		569
Net income (loss)	$	2,677	$	(3,651)	$	(332)	$	(62)	$	(841)	$	(20)	$	235	$	(1,994)


	Nine Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	6,385	$	3,245	$	1,845	$	211	$	863	$	3	$	(3,633)	$	8,919
Fuel, purchased power costs and delivery fees	(5,133)		(805)		(897)		(115)		(515)		—		3,633		(3,832)
Operating costs	(94)		(560)		(192)		(22)		(314)		(66)		(1)		(1,249)
Depreciation and amortization	(229)		(340)		(540)		(14)		(101)		(12)		(48)		(1,284)
Selling, general and administrative expenses	(489)		(58)		(66)		(18)		(52)		(20)		(52)		(755)

Impairment of long-lived assets	—		—		—		—		(356)		—		—		(356)
Operating income (loss)	440		1,482		150		42		(475)		(95)		(101)		1,443
Other income	1		3		1		1		4		8		1		19
Other deductions	—		(7)		(30)		—		4		(2)		—		(35)
Interest expense and related charges	(8)		6		(6)		6		(2)		—		(537)		(541)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		44		44
Equity in earnings of unconsolidated investment	—		—		4		—		—		—		—		4
Income (loss) before income taxes	433		1,484		119		49		(469)		(89)		(593)		934
Income tax expense	—		—		—		—		—		—		(283)		(283)
Net income (loss)	$	433	$	1,484	$	119	$	49	$	(469)	$	(89)	$	(876)	$	651

Consolidated results decreased $3.844 billion to a net operating loss of $2.401 billion in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. The change in results is driven by the Winter Storm Uri impacts, including the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs. Results were also adversely impacted by $771 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $444 million in pre-tax unrealized gains on commodity hedging transactions in 2020. Power, natural gas and coal forward market curves moved up during the nine months ended September 30, 2021, driving these net pre-tax unrealized losses on commodity hedging transactions.

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

Interest expense and related charges decreased $253 million to $288 million in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020 driven by $92 million in unrealized mark-to-market gains on interest rate swaps in 2021 compared to $181 million in unrealized mark-to-market losses on interest rate swaps in 2020. See Note 17 to the Financial Statements.

For the nine months ended September 30, 2021 and 2020, the Impacts of the Tax Receivable Agreement totaled income of $31 million and $44 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the nine months ended September 30, 2021, income tax benefit totaled $569 million and the effective tax rate was 22.2%. For the nine months ended September 30, 2020, income tax expense totaled $283 million and the effective tax rate was 30.3%. See Note 6 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Discussion of Adjusted EBITDA

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

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

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

When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).

Adjusted EBITDA — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) $ Change			Nine Months Ended September 30,					Favorable (Unfavorable) $ Change
	2021		2020				2021			2020
Net income (loss)	$	10	$	442	$	(432)		$	(1,994)		$	651	$	(2,645)
Income tax expense (benefit)	31		199		(168)			(569)			283		(852)
Interest expense and related charges (a)	124		101		23			288			541		(253)
Depreciation and amortization (b)	489		431		58			1,416			1,341		75
EBITDA before Adjustments	654		1,173		(519)			(859)			2,816		(3,675)
Unrealized net (gain) loss resulting from hedging transactions	589		(321)		910			771			(444)		1,215
Generation plant retirement expenses	5		43		(38)			19			43		(24)
Fresh start/purchase accounting impacts	(17)		—		(17)			(96)			34		(130)
Impacts of Tax Receivable Agreement	(35)		(58)		23			(31)			(44)		13

Non-cash compensation expenses	11		16		(5)			40			46		(6)
Transition and merger expenses	(2)		(2)		—			(17)			17		(34)
Impairment of long-lived assets	2		272		(270)			40			356		(316)
Loss on disposal of investment in NELP	—		—		—			—			29		(29)
COVID-19-related expenses (c)	1		3		(2)			6			18		(12)
Winter Storm Uri impact (d)	(33)		—		(33)			866			—		866
Other, net	(2)		11		(13)			5			14		(9)
Adjusted EBITDA	$	1,173	$	1,137	$	36		$	744		$	2,885	$	(2,141)

(a)Includes unrealized mark-to-market net gains on interest rate swaps of $13 million and $11 million for the three months ended September 30, 2021 and 2020, respectively, and unrealized mark-to-market net gains on interest rate swaps of $92 million and unrealized mark-to-market net losses on interest rate swaps of $181 million for the nine months ended September 30, 2021 and 2020, respectively.

(b)Includes nuclear fuel amortization in the Texas segment of $21 million and $20 million for the three months ended September 30, 2021 and 2020, respectively, and $61 million and $57 million for the nine months ended September 30, 2021 and 2020, respectively.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

(d)For the nine months ended September 30, 2021, includes the following amounts, which we believe are not reflective of our operating performance: $194 million for allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols (net present value of $45 million applying a 4.25% discount rate); accrual of Koch earn-out disputed amounts of $286 million that the Company is contesting and does not believe should be paid; $386 million for future bill credits related to Winter Storm Uri as further described below and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are for the remainder of 2021 (approximately $43 million), 2022 (approximately $185 million), 2023 (approximately $84 million), 2024 (approximately $18 million) and 2025 (approximately $8 million). The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance.

Consistent with the Company's hedging practices to provide a more predictable financial performance over time, Adjusted EBITDA totaled $1.173 billion and $1.137 billion for the three months ended September 30, 2021 and 2020, respectively, despite significant moves in commodity prices during the period.


	Three Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	779	$	4	$	(233)	$	(18)	$	(375)	$	(6)	$	(141)	$	10
Income tax expense	2		—		—		—		—		—		29		31
Interest expense and related charges (a)	2		(3)		5		(1)		1		1		119		124
Depreciation and amortization (b)	53		200		164		15		40		—		17		489
EBITDA before Adjustments	836		201		(64)		(4)		(334)		(5)		24		654
Unrealized net (gain) loss resulting from hedging transactions	(739)		654		254		39		381		—		—		589
Generation plant retirement expenses	—		—		—		—		4		—		1		5
Fresh start/purchase accounting impacts	(2)		(2)		—		—		(13)		—		—		(17)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(35)		(35)

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

COVID-19-related expenses (c)	—		1		—		—		—		—		—		1
Winter Storm Uri impacts (d)	(31)		(2)		—		—		—		—		—		(33)
Other, net	5		4		3		1		(2)		1		(14)		(2)
Adjusted EBITDA	$	65	$	858	$	193	$	36	$	36	$	(4)	$	(11)	$	1,173

(a)Includes $13 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $21 million in Texas segment.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

(d)Includes bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri as the credits are applied to customer bills and a small reduction in ERCOT default uplift charges, partially offset by ongoing Winter Storm Uri related legal fees and other costs.


	Three Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	109	$	908	$	100	$	29	$	(368)	$	(60)	$	(276)	$	442
Income tax expense	—		—								—		199		199
Interest expense and related charges (a)	2		(2)		2		(3)		1		—		101		101
Depreciation and amortization (b)	67		127		181		5		22		12		17		431
EBITDA before Adjustments	178		1,033		283		31		(345)		(48)		41		1,173
Unrealized net (gain) loss resulting from hedging transactions	(316)		(78)		(40)		(9)		122		—		—		(321)
Generation plant retirement expenses	—		—		—		—		43		—		—		43
Fresh start/purchase accounting impacts	(6)		—		6		—		—		—		—		—
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(58)		(58)

Non-cash compensation expenses	—		—		—		—		—		—		16		16
Transition and merger expenses	1		—		(5)		—		—		—		2		(2)
Impairment of long-lived assets	—		—		—		—		272		—		—		272

COVID-19-related expenses (c)	—		2		—		—		1		—		—		3
Other, net	3		15		1		1		—		2		(11)		11
Adjusted EBITDA	$	(140)	$	972	$	245	$	23	$	93	$	(46)	$	(10)	$	1,137

(a)Includes $11 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $20 million in Texas segment.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.


	Nine Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	2,677	$	(3,651)	$	(332)	$	(62)	$	(841)	$	(20)	$	235	$	(1,994)
Income tax expense (benefit)	2		—		—		—		—		—		(571)		(569)
Interest expense and related charges (a)	7		(10)		11		(9)		1		1		287		288
Depreciation and amortization (b)	160		523		553		30		99		—		51		1,416
EBITDA before Adjustments	2,846		(3,138)		232		(41)		(741)		(19)		2		(859)
Unrealized net (gain) loss resulting from hedging transactions	(2,840)		2,269		407		120		815		—		—		771
Generation plant retirement expenses	—		—		—		—		19		—		—		19
Fresh start/purchase accounting impacts	1		(3)		(74)		—		(20)		—		—		(96)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(31)		(31)

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

COVID-19-related expenses (c)	—		3		1		—		1		—		1		6
Winter Storm Uri impacts (d)	354		511		—		—		1		—		—		866
Other, net	17		6		7		2		2		2		(31)		5
Adjusted EBITDA	$	376	$	(350)	$	573	$	81	$	115	$	(32)	$	(19)	$	744

(a)Includes $92 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $61 million in Texas segment.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

(d)Includes the following amounts, which we believe are not reflective of our operating performance: $194 million for allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols (net present value of $45 million applying a 4.25% discount rate); accrual of Koch earn-out disputed amounts of $286 million that the Company is contesting and does not believe should be paid; $386 million for future bill credits related to Winter Storm Uri as further described below and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are for the remainder of 2021 (approximately $43 million), 2022 (approximately $185 million), 2023 (approximately $84 million), 2024 (approximately $18 million) and 2025 (approximately $8 million). The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance.


	Nine Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	433	$	1,484	$	119	$	49	$	(469)	$	(89)	$	(876)	$	651
Income tax expense	—		—		—		—		—		—		283		283
Interest expense and related charges (a)	8		(6)		6		(6)		2		—		537		541
Depreciation and amortization (b)	229		397		540		14		101		12		48		1,341
EBITDA before Adjustments	670		1,875		665		57		(366)		(77)		(8)		2,816
Unrealized net (gain) loss resulting from hedging transactions	(114)		(449)		(37)		(1)		157		—		—		(444)
Generation plant retirement expenses	—		—		—		—		43		—		—		43
Fresh start/purchase accounting impacts	1		(4)		23		—		14		—		—		34
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(44)		(44)

Non-cash compensation expenses	—		—		—		—		—		—		46		46
Transition and merger expenses	8		1		1		—		—		(3)		10		17
Impairment of long-lived assets	—		—		—		—		356		—		—		356
Loss on disposal of investment in NELP	—		—		29		—		—		—		—		29
COVID-19-related expenses (c)	—		12		2		—		3		—		1		18

Other, net	7		17		8		3		2		2		(25)		14
Adjusted EBITDA	$	572	$	1,452	$	691	$	59	$	209	$	(78)	$	(20)	$	2,885

(a)Includes $181 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $57 million in Texas segment.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

Retail Segment — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) Change			Nine Months Ended September 30,					Favorable (Unfavorable) Change
	2021		2020				2021			2020
Operating revenues:
Revenues in ERCOT	$	1,917	$	1,839	$	78		$	4,521		$	4,536	$	(15)
Revenues in Northeast/Midwest	624		683		(59)			1,715			1,862		(147)
Amortization expense	2		7		(5)			(1)			(1)		—
Unrealized net losses on hedging activities (a)	(383)		(8)		(375)			(406)			(12)		(394)
Total operating revenues	2,160		2,521		(361)			5,829			6,385		(556)
Fuel, purchased power costs and delivery fees:
Purchases from affiliates	(1,607)		(1,859)		252			(3,784)			(3,761)		(23)
Unrealized net gains (losses) on hedging activities with affiliates	1,117		323		794			3,244			127		3,117
Unrealized net gains (losses) on hedging activities	5		1		4			2			(1)		3
Delivery fees	(595)		(570)		(25)			(1,472)			(1,446)		(26)
Other costs (b)	(15)		(14)		(1)			(335)			(52)		(283)
Total fuel, purchased power costs and delivery fees	(1,095)		(2,119)		1,024			(2,345)			(5,133)		2,788










Net income	$	779	$	109	$	670		$	2,677		$	433	$	2,244


	Three Months Ended September 30,						Favorable (Unfavorable) Change			Nine Months Ended September 30,							Favorable (Unfavorable) Change
	2021			2020					2021				2020
Adjusted EBITDA	$	65		$	(140)		$	205		$	376			$	572		$	(196)

Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	17,732			16,573			1,159			44,215				41,547			2,668
Sales volumes in Northeast/Midwest	10,034			11,103			(1,069)			27,558				28,640			(1,082)
Total retail electricity sales volumes	27,766			27,676			90			71,773				70,187			1,586
Weather (North Texas average) - percent of normal (c):
Cooling degree days	91.2		%	89.0		%				86.9		%		91.0		%
Heating degree days	—		%	—		%				117.1		%		88.0		%

(a)During both the three and nine months ended September 30, 2021, a net loss of $(357) million was recognized in operating revenues due to the discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

(b)For the nine months ended September 30, 2021, includes $162 million of future bill credits to large commercial and industrial customers.

(c)Weather data is obtained from Weatherbank, Inc. For the three and nine months ended September 30, 2021, normal is defined as the average over the 10-year period from September 2011 to September 2020. For the three and nine months ended September 30, 2020, normal is defined as the average over the 10-year period from September 2010 to September 2019.

Net income increased by $670 million to $779 million and Adjusted EBITDA increased by $205 million to $65 million in the three months ended September 30, 2021 compared to the three months ended September 30, 2020. Net income increased by $2.244 billion to $2.677 billion and Adjusted EBITDA decreased by $196 million to $376 million in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.


	Three Months Ended September 30, 2021 Compared to 2020		Nine Months Ended September 30, 2021 Compared to 2020
Monetization of certain commercial positions	$	30	$	145
Winter Storm Uri, including bill credits	13		(551)
Higher margins	167		246
Other driven by higher SG&A	(5)		(36)
Change in Adjusted EBITDA	$	205	$	(196)
Favorable impact of higher unrealized net gains on hedging activities	423		2,726
Future bill credits and other costs related to Winter Storm Uri	31		(354)
Decrease in depreciation and amortization expenses	14		69
Change in transition and merger and other expenses	(3)		(1)
Change in net income	$	670	$	2,244

Generation — Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020


	Three Months Ended September 30,
	Texas						East						West						Sunset
	2021			2020			2021			2020			2021			2020			2021			2020
Operating revenues:
Electricity sales	$	462		$	155		$	411		$	210		$	134		$	78		$	265		$	280
Capacity revenue from ISO/RTO	—			—			(13)			(25)			1			—			51			40
Sales to affiliates	1,078			1,307			413			436			1			1			113			116
Rolloff of unrealized net gains (losses) representing positions settled in the current period	(17)			138			(56)			41			55			4			69			(41)
Unrealized net gains (losses) on hedging activities	(153)			129			225			67			(101)			1			(500)			(44)
Unrealized net (losses) on hedging activities with affiliates	(527)			(188)			(472)			(85)			—			—			(118)			(48)
Other revenues	—			—			—			—			—			—			(2)			(4)
Operating revenues	843			1,541			508			644			90			84			(122)			299
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(458)			(293)			(536)			(301)			(84)			(41)			(265)			(235)
Fuel for generation facilities and purchased power costs from affiliates	1			2			1			(4)			—			—			(1)			1
Unrealized gains (losses) from hedging activities	43			(1)			49			19			7			4			168			11
Unrealized net losses on hedging activities with affiliates	—			—			—			(2)			—			—			—			—
Ancillary and other costs	(68)			(36)			(10)			(7)			(1)			(1)			(2)			(4)
Fuel, purchased power costs and delivery fees	(482)			(328)			(496)			(295)			(78)			(38)			(100)			(227)










Net income (loss)	$	4		$	908		$	(233)		$	100		$	(18)		$	29		$	(375)		$	(368)













Adjusted EBITDA	$	858		$	972		$	193		$	245		$	36		$	23		$	36		$	93
Production volumes (GWh):
Natural gas facilities	9,597			10,722			14,760			16,248			1,635			1,347
Lignite and coal facilities	7,969			7,226															11,454			9,510
Nuclear facilities	5,254			5,270
Solar/Battery facilities	135			133									—
Capacity factors:
CCGT facilities	52.7		%	58.7		%	60.7		%	66.4		%	72.6		%	59.7		%
Lignite and coal facilities	93.7		%	85.0		%													71.2		%	59.2		%
Nuclear facilities	103.5		%	103.8		%
Weather - percent of normal (a):
Cooling degree days	92.4		%	96.0		%	101.3		%	108.0		%	94.5		%	114.0		%	109.6		%	102.0		%
Heating degree days	—		%	—		%	37.2		%	144.0		%	—		%	—		%	47.7		%	98.0		%

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


	Three Months Ended September 30,							Three Months Ended September 30,
	2021			2020				2021		2020
Market pricing						Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	38.64		$	24.87	PJM West Hub		$	51.37	$	28.35
			AEP Dayton Hub	$	50.29	$	28.44
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	4.27		$	1.95	NYISO Zone C		$	43.95	$	23.09
			Massachusetts Hub	$	52.69	$	27.22
Average natural gas price (a):						Indiana Hub		$	51.59	$	29.84
TetcoM3 ($/MMBtu)	$	3.75		$	1.45	Northern Illinois Hub		$	48.19	$	25.80
Algonquin Citygates ($/MMBtu)	$	3.86		$	1.52

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

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the three months ended September 30, 2021 compared to the three months ended September 30, 2020.


	Three Months Ended September 30, 2021 Compared to 2020
	Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	$	(144)	$	(44)	$	14	$	(49)
Winter Storm Uri impact	(3)		—		—		—
Favorable/(unfavorable) change in other operating costs	26		(6)		(1)		(11)
Favorable change in selling, general and administrative expenses	5		1		1		6
Other (a)	2		(3)		(1)		(3)
Change in Adjusted EBITDA	$	(114)	$	(52)	$	13	$	(57)
Favorable/(unfavorable) change in depreciation and amortization	(73)		17		(10)		(18)
Change in unrealized net losses on hedging activities	(732)		(294)		(48)		(259)
Impairment of long-lived assets	(2)		—		—		272
Generation plant retirement expenses	—		—		—		39
Fresh start/purchase accounting impacts	2		6		—		13
Transition and merger expenses	—		(5)		—		—
Winter Storm Uri impact (ERCOT default uplift and legal disputes)	2		—		—		—
Other (including interest and COVID-19 related expenses)	13		(5)		(2)		3
Change in Net income (loss)	$	(904)	$	(333)	$	(47)	$	(7)

(a) For the three months ended September 30, 2021, includes insurance proceeds of $5 million in the Sunset segment and $4 million in the Texas segment.

The change in Texas segment results was driven by lower revenue net of fuel, unrealized hedging losses in current year versus unrealized hedging gains in prior year and higher depreciation expense.

The change in East segment results was driven by lower revenue net of fuel and unrealized hedging losses in current year versus unrealized hedging gains in prior year.

The change in West segment results was driven by unrealized hedging losses in current year versus unrealized hedging gains in prior year, partially offset by a favorable change in revenue net of fuel.

The change in Sunset segment results was driven by lower revenue net of fuel, higher operating costs and larger unrealized hedging losses in current year versus prior year.

Generation — Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020


	Nine Months Ended September 30,
	Texas						East						West						Sunset
	2021			2020			2021			2020			2021			2020			2021			2020
Operating revenues:
Electricity sales	$	1,502		$	598		$	986		$	582		$	302		$	204		$	701		$	641
Capacity revenue from ISO/RTO	—			—			(14)			(34)			1			—			133			124
Sales to affiliates	2,310			2,185			1,178			1,287			3			3			294			286
Rolloff of unrealized net gains (losses) representing positions settled in the current period	(170)			74			(24)			138			44			(21)			15			(173)
Unrealized net gains (losses) on hedging activities	(31)			322			357			(10)			(179)			25			(752)			75
Unrealized net gains (losses) on hedging activities with affiliates	(2,153)			66			(819)			(119)			—			—			(272)			(74)
Other revenues	—			—			74			1			—			—			(10)			(16)
Operating revenues	1,458			3,245			1,738			1,845			171			211			109			863
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(2,439)			(695)			(1,321)			(888)			(176)			(110)			(644)			(527)
Fuel for generation facilities and purchased power costs from affiliates	(1)			5			—			(8)			—			—			(2)			2
Unrealized gains (losses) from hedging activities	85			(13)			79			28			15			(3)			194			15

Ancillary and other costs	(1,778)			(102)			(27)			(29)			(3)			(2)			(6)			(5)
Fuel, purchased power costs and delivery fees	(4,133)			(805)			(1,269)			(897)			(164)			(115)			(458)			(515)










Net income (loss)	$	(3,651)		$	1,484		$	(332)		$	119		$	(62)		$	49		$	(841)		$	(469)













Adjusted EBITDA	$	(350)		$	1,452		$	573		$	691		$	81		$	59		$	115		$	209
Production volumes (GWh):
Natural gas facilities	23,142			27,111			40,781			41,682			3,998			3,755
Lignite and coal facilities	19,441			18,717															28,582			20,696
Nuclear facilities	15,343			15,045
Solar/Battery facilities	357			341									3
Capacity factors:
CCGT facilities	43.1		%	50.7		%	56.7		%	57.8		%	59.8		%	56.1		%
Lignite and coal facilities	77.1		%	74.2		%													60.0		%	43.4		%
Nuclear facilities	101.8		%	99.8		%
Weather - percent of normal (a):
Cooling degree days	89.8		%	98.0		%	107.2		%	106.0		%	95.5		%	126.0		%	112.1		%	103.0		%
Heating degree days	122.9		%	81.0		%	95.3		%	93.0		%	108.2		%	91.0		%	94.4		%	89.0		%

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


	Nine Months Ended September 30,							Nine Months Ended September 30,
	2021			2020				2021		2020
Market pricing						Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	186.71		$	20.25	PJM West Hub		$	39.95	$	23.91
			AEP Dayton Hub	$	40.15	$	24.06
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	3.52		$	1.82	NYISO Zone C		$	31.94	$	19.26
			Massachusetts Hub	$	46.96	$	24.06
Average natural gas price (a):						Indiana Hub		$	43.99	$	26.23
TetcoM3 ($/MMBtu)	$	3.11		$	1.55	Northern Illinois Hub		$	37.77	$	22.12
Algonquin Citygates ($/MMBtu)	$	3.93		$	1.75

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

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.


	Nine Months Ended September 30, 2021 Compared to 2020
	Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	$	(362)	$	(160)	$	31	$	(88)
Winter Storm Uri impact	(1,551)		50		—		17
Favorable/(unfavorable) change in other operating costs	42		(9)		(5)		(33)
Change in selling, general and administrative expenses	68		5		(4)		17
Other (a)	1		(4)		—		(7)
Change in Adjusted EBITDA	$	(1,802)	$	(118)	$	22	$	(94)
Favorable/(unfavorable) change in depreciation and amortization	(126)		(13)		(16)		2
Change in unrealized net losses on hedging activities	(2,718)		(444)		(121)		(658)
Impairment of long-lived assets	(2)		—		—		318
Generation plant retirement expenses	—		—		—		24
Fresh start/purchase accounting impacts	(1)		97		—		34
Transition and merger expenses	1		1		—		—
Loss on disposal of investment in NELP	—		29		—		—
Winter Storm Uri impact (ERCOT default uplift and legal disputes)	(511)		—		—		(1)
Other (including interest and COVID-19 related expenses)	24		(3)		4		3
Change in Net income (loss)	$	(5,135)	$	(451)	$	(111)	$	(372)

(a) For the nine months ended September 30, 2021, includes insurance proceeds of $67 million in the Texas segment and $5 million in the Sunset segment.

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

The change in East segment results was driven by lower revenue net of fuel, loss on disposal of equity method investment in NELP for 100% ownership of NJEA (see Note 17 to the Financial Statements) in 2020, and unrealized hedging losses in current year versus unrealized hedging gains in prior year.

The change in West segment results was driven by unrealized hedging losses in current year versus unrealized gains in prior year, partially offset by a favorable change in revenue net of fuel.

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

Asset Closure Segment — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) Change			Nine Months Ended September 30,					Favorable (Unfavorable) Change
	2021		2020				2021			2020
Operating revenues	$	—	$	1	$	(1)		$	—		$	3	$	(3)

Operating costs	(1)		(47)		46			$	(19)		$	(66)	$	47
Depreciation and amortization	—		(11)		11			—			(12)		12
Selling, general and administrative expenses	(5)		(8)		3			(20)			(20)		—


Operating loss	(6)		(65)		59			(39)			(95)		56
Other income	1		5		(4)			20			8		12
Other deductions	—		—		—			—			(2)		2
Interest expense and related charges	(1)		—		(1)			(1)			—		(1)

Loss before income taxes	(6)		(60)		54			(20)			(89)		69

Net loss	$	(6)	$	(60)	$	54		$	(20)		$	(89)	$	69







Adjusted EBITDA	$	(4)	$	(46)	$	42		$	(32)		$	(78)	$	46

Operating costs for the three and nine months ended September 30, 2021 and 2020 included ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The nine months ended September 30, 2021 includes a gain on the settlement of rail transportation disputes (see Note 17 to the Financial Statements).

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2021 and 2020. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $771 million in unrealized net losses and $444 million in unrealized net gains for the nine months ended September 30, 2021 and 2020, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.


	Nine Months Ended September 30,
	2021		2020
Commodity contract net liability at beginning of period	$	(75)	$	(279)
Settlements/termination of positions (a)	(202)		74
Changes in fair value of positions in the portfolio (b)	(569)		370

Other activity (c)	(116)		7
Commodity contract net asset (liability) at end of period	$	(962)	$	172

(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The nine months ended September 30, 2021 and 2020 include reversals of $1 million and $7 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius acquisition and Ambit acquisition. The nine months ended September 30, 2020 includes reversal of $1 million of previously recorded losses related to Vistra beginning balances. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(b)Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(c)Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at September 30, 2021, scheduled by the source of fair value and contractual settlement dates of the underlying positions.


	Maturity dates of unrealized commodity contract net liability at September 30, 2021
	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
Prices actively quoted	$	(554)	$	(85)	$	1	$	—	$	(638)
Prices provided by other external sources	(13)		(90)		5		(2)		(100)
Prices based on models	(57)		2		(80)		(89)		(224)
Total	$	(624)	$	(173)	$	(74)	$	(91)	$	(962)

FINANCIAL CONDITION

Operating Cash Flows

Cash used in operating activities totaled $493 million for the nine months ended September 30, 2021 compared to cash provided by operating activities of $2.350 billion for the nine months ended September 30, 2020. The unfavorable change of $2.843 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties.

Depreciation and amortization expense reported as a reconciling adjustment in the condensed consolidated statements of cash flows exceeds the amount reported in the condensed consolidated statements of operations by $196 million and $228 million for the nine months ended September 30, 2021 and 2020, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the condensed consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other condensed consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees.

Investing Cash Flows

Cash used in investing activities totaled $843 million and $927 million for the nine months ended September 30, 2021 and 2020, respectively. Capital expenditures totaled $790 million and $838 million for the nine months ended September 30, 2021 and 2020, respectively, and consisted of the following:


	Nine Months Ended September 30,
	2021		2020
Capital expenditures, including LTSA prepayments	$	437	$	439
Nuclear fuel purchases	$	30	$	69
Growth and development expenditures	$	323	$	330
Capital expenditures	$	790	$	838

Cash used in investing activities also reflected net purchases of environmental allowances of $145 million and $119 million for the nine months ended September 30, 2021 and 2020, respectively. In the nine months ended September 30, 2021 and 2020, we also received insurance proceeds of $74 million and $15 million, respectively.

Financing Cash Flows

Cash provided by financing activities totaled $1.279 billion in the nine months ended September 30, 2021 compared to cash used of $1.348 billion for the nine months ended September 30, 2020. The change was primarily driven by:

the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021;
redemption of $747 million principal amount of outstanding of Vistra unsecured senior notes in 2020;
$500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 in March 2021;
net borrowings of $175 million under the accounts receivable financing facilities in 2021;
net repayment of $350 million in short-term borrowings under the Revolving Credit Facility in 2020;
repayment of $100 million of term loans under the Vistra Operations Credit Facility in March 2020;

partially offset by $175 million in cash paid for share repurchases in 2021.

Debt Activity

See Note 9 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2021:


	September 30, 2021		December 31, 2020		Change
Cash and cash equivalents	$	351	$	406	$	(55)
Vistra Operations Credit Facilities — Revolving Credit Facility	1,720		1,988		(268)
Vistra Operations — Alternate Letter of Credit Facility	—		5		(5)
Total available liquidity (a)	$	2,071	$	2,399	$	(328)

____________

(a)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 to the Financial Statements for detail on our accounts receivable financing.

The $328 million decrease in available liquidity for the nine months ended September 30, 2021 was primarily driven by cash used in operations, including higher cash margin deposits posted with third parties, $790 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), $175 million in cash paid for share repurchases, $219 million in dividends paid to stockholders and a $268 million increase in letters of credit outstanding under the Revolving Credit Facility, partially offset by cash received from the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021, $500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 and $175 million in net cash borrowings under the accounts receivable financing facilities.

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

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

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 10 to the Financial Statements for discussion of the Vistra Operations Credit Facilities.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors, including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other business purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.

At September 30, 2021, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:

$1.048 billion in cash has been posted with counterparties as compared to $257 million posted at December 31, 2020;
$57 million in cash has been received from counterparties as compared to $33 million received at December 31, 2020;
$1.316 billion in letters of credit have been posted with counterparties as compared to $878 million posted at December 31, 2020; and
$27 million in letters of credit have been received from counterparties as compared to $18 million received at December 31, 2020.

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

Income Tax Payments

In the next 12 months, we do not expect to make federal income tax payments due to Vistra's loss position in 2021 and use of NOL carryforwards. We expect to make approximately $31 million in state income tax payments, offset by $9 million in state tax refunds, and $2 million in TRA payments in the next 12 months.

For the nine months ended September 30, 2021, there were no federal income tax payments, $46 million in state income tax payments, $2 million in state income tax refunds and no TRA payments.

Financial Covenants

The Credit Facilities Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not exceed 4.25 to 1.00. Although the period ended September 30, 2021 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date.

See Note 10 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Collateral Support Obligations

The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at September 30, 2021, Vistra has posted letters of credit in the amount of $74 million with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $384 million in the form of letters of credit, $20 million in the form of a surety bond and $1 million of cash at September 30, 2021 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

Material Cross Default/Acceleration Provisions

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

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.550 billion at September 30, 2021.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.

Under the Vistra Operations Senior Unsecured Indentures and the Vistra Operations Senior Secured Indenture, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Alternate LOC Facilities, and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract.

The Receivables Facility contains a cross-default provision. The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, or, in the case of TXU Energy or any of the other Originators, in a principal amount of at least $50 million, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated.

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

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

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

Guarantees

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

COMMITMENTS AND CONTINGENCIES

See Note 11 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

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