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

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

The following discussion and analysis of our financial condition and results of operations for the years ended December 31, 2019, 2018 and 2017 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements. Results are impacted by the effects of the Ambit Transaction, the Crius Transaction and the Merger (see Note 2 to the Financial Statements). The discussion and analysis of our financial condition and results of operations for the year ended December 31, 2017 and for the year ended December 31, 2018 compared to the year ended December 31, 2017 are included in Item 7. Management's Discussion and Analysis of Financial Condition and Results in our 2018 Form 10-K and is incorporated herein by reference. Operational results for four facilities retired in late 2019 were recast from the MISO segment to the Asset Closure segment (see Note 4 to the Financial Statements). The recast is reflected in the results of operations for the years ended December 31, 2019 and 2018, but the four retired facilities were not owned by Vistra nor did the MISO segment exist during the year ended December 31, 2017. Therefore, the recast does not impact the comparison of the results of operations for the years ended December 31, 2018 and December 31, 2017 beyond the recast shown below for the year ended December 31, 2018.

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

Business

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

Operating Segments

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), (v) MISO and (vi) Asset Closure. See Note 20 to the Financial Statements for further information concerning reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

Acquisitions and Merger

Ambit Transaction — On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra Energy, completed the acquisition of Ambit (Ambit Transaction). See Note 2 to the Financial Statements for a summary of the Ambit Transaction and business combination accounting.

Crius Transaction — On July 15, 2019, Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra Energy, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). See Note 2 to the Financial Statements for a summary of the Crius Transaction and business combination accounting.

Dynegy Merger Transaction — On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement. See Note 2 to the Financial Statements for a summary of the Merger transaction and business combination accounting.

Acquisition, Development and Disposition of Generation Facilities

See Note 3 to the Financial Statements for a summary of our solar generation and battery energy storage projects. See Note 4 to the Financial Statements for a summary of our generation plant retirements in 2018 and 2019.

Dividend Program

In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. See Note 14 to the Financial Statements for more information about our dividend program.

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Share Repurchase Program

In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of our outstanding common stock may be purchased, and in November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $1.250 billion of our outstanding stock may be purchased, resulting in an aggregate $1.750 billion share repurchase program. See Note 14 to the Financial Statements for more information concerning the share repurchase program, including shares repurchased and remaining amounts available under the program.

Debt Activity

We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize our capital structure, maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities and/or reduce ongoing interest expense. In 2019, we completed several transactions that we believe, in the aggregate, advanced all of these goals. See Note 11 to the Financial Statements for details of our long-term debt activity and Note 10 to the Financial Statements for details of the accounts receivable securitization program.

Capacity Markets

PJM — Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year:

2019-20202020-20212021-2022
BaseCPCPCP
RTO zone (a)$80.00$100.00$88.32$140.00
ComEd zone182.77202.77188.12195.55
MAAC zone80.00100.0086.04140.00
EMAAC zone99.77119.77187.87165.73
ATSI zone80.00100.0076.53171.33
PPL zone80.00100.0086.04140.00

(a)Planning Year 2020-2021 includes Duke Energy Ohio Kentucky (DEOK) zone which cleared at $130.00 per MW-day. RTO Zone excluding DEOK Zone was $76.53 per MW-day.

Our capacity sales, net of purchases, aggregated by planning year and capacity type through planning year 2022-2023, are as follows:

2019-20202020-20212021-20222022-2023
Base auction capacity sold, net (MW)837———
CP auction capacity sold, net (MW)8,3428,5828,963—
Bilateral capacity sold, net (MW)160200200200
Total segment capacity sold, net (MW)9,3398,7829,163200
Average price per MW-day$134.43$130.04$160.55$170.00

NYISO — The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:

Summer 2019Winter 2019 - 2020
Price per kW-month$1.30$0.18

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Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through bilateral trades. Our capacity sales, aggregated by season through summer 2022, are as follows:

Winter 2019 - 2020Summer 2020Winter 2020 - 2021Summer 2021Winter 2021 - 2022
Auction capacity sold (MW)102————
Bilateral capacity sold (MW)91695554240333
Total capacity sold (MW)1,01895554240333
Average price per kW-month$0.86$1.82$0.83$2.69$1.94

ISO-NE — The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each planning year:

2019-20202020-20212021-20222022-20232023-2024
Price per kW-month$7.03$5.30$4.63$3.80$—

Performance incentive rules increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level. We continue to market and pursue longer term multi-year capacity transactions that extend planning year 2023-2024.

2019-20202020-20212021-20222022-20232023-2024
Auction capacity sold (MW)3,2373,1122,9393,137—
Bilateral capacity sold (MW)711501709520
Total capacity sold (MW)3,3083,2623,1093,23220
Average price per kW-month$6.91$5.35$4.58$3.92$4.93

MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year:

2019-2020
Price per MW-day$2.99

MISO capacity sales through planning year 2022-2023 are as follows:

2019-20202020-20212021-20222022-2023
Bilateral capacity sold in MISO (MW)2,1281,974786432
Base auction capacity sold in PJM (MW)220———
CP auction capacity sold in PJM (MW)133344415125
Total MISO segment capacity sold (MW)2,4812,3181,201557
Average price per kW-month$3.81$3.52$5.06$5.01

CAISO — Our capacity sales, aggregated by calendar year for 2020 through 2022 for Moss Landing, are as follows:

202020212022
Bilateral capacity sold (Avg MW)1,020——

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Key Operational Risks and Challenges

Following is a discussion of certain key operational risks and challenges facing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material effect on our business, results of operations, liquidity, financial condition, cash flow, reputation, prospects and the market price for our securities (including our common stock). See also Item 1A. Risk Factors in this annual report on Form 10-K for additional discussion on risks that could have a material effect on our results of operations, liquidity, financial condition, cash flow, reputation, prospects and the market price for our securities (including our common stock).

Natural Gas Price and Market Heat Rate Exposure

The price of power is typically set by natural gas-fueled generation facilities, with wholesale prices generally tracking increases or decreases in the price of natural gas, with exceptions such as those periods during which ERCOT power prices rise significantly as a result of the scarcity of available generation resources relative to power demand. In recent years, natural gas supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural gas extraction; this supply/demand environment has resulted in historically low natural gas prices, and such prices have historically been volatile. The table below shows the general decline in forward natural gas prices over the last several years (amounts are per MMBtu.)

vistra-20191231_g2.jpg

(a)Settled prices represent the average of NYMEX Henry Hub monthly settled prices of financial contracts for the year ending on the date presented. Forward prices represent the three-year average of NYMEX Henry Hub monthly forward prices at the date presented. Three-year forward prices are presented as such period is generally deemed to be a liquid period.

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In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating power at our nuclear-, lignite- and coal-fueled facilities, which represent a significant portion of our generation capacity. Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as wholesale electricity prices change either as a result of changes in natural gas prices or market heat rates, because of the effect on our operating margins. A persistent decline in the price of natural gas, if not offset by an increase in market heat rates, would likely have a material adverse effect on our results of operations, liquidity and financial condition, predominantly related to the production of power generation volumes in excess of the volumes utilized to service our retail customer load requirements and wholesale hedges.

The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. Our market heat rate exposure is impacted by changes in the availability of generation resources, such as additions and retirements of generation facilities, and mix of generation assets. For example, increasing renewable (wind and solar) generation capacity generally depresses market heat rates, particularly during periods when total demand is relatively low. However, increasing penetration of renewable generation capacity may also contribute to greater volatility of wholesale market prices independent of changes in the price of natural gas, given their intermittent nature. Decreases in market heat rates decrease the value of our generation assets because lower market heat rates result in lower wholesale electricity prices, and vice versa. In 2018 and prior years, even though market heat rates generally increased, wholesale electricity prices declined due to the greater effect of falling natural gas prices. Power price declines in the PJM, NYISO and ISO-NE markets in 2019 relative to 2018 also reflected the impact of lower natural gas prices. However, in the ERCOT market, wholesale market prices increased in 2019 relative to 2018, as the increase in market heat rates had a greater effect than the impact of falling natural gas prices.

As a result of our exposure to the variability of natural gas prices and market heat rates, retail sales and hedging activities are critical to our operating results and maintaining consistent cash flow levels.

Our integrated power generation and retail electricity business provides us opportunities to hedge our generation position utilizing retail electricity markets as a sales channel. In addition, our approach to managing electricity price risk focuses on the following:

  • employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related contracts intended to partially hedge gross margins;

  • continuing focus on cost management to better withstand gross margin volatility;

  • following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the magnitude and costs of commodity price, liquidity risk and retail demand variability, and

  • improving retail customer service to attract and retain high-value customers.

We have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices that have corresponded to declines in natural gas prices. While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

Estimated hedging levels for generation volumes in ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO at December 31, 2019 were as follows:

20202021
Coal/Nuclear/Renewable Generation:
ERCOT95%71%
PJM100%91%
MISO100%45%
Gas Generation:
ERCOT81%10%
PJM84%19%
NYISO/ISO-NE100%45%
CAISO100%34%

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The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed heat rate of 7.2 MWh/MMBtu) on realized pretax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of December 31, 2019.

Balance 2020 (a)2021
ERCOT:
Coal/Nuclear/Renewable Generation: $2.50/MWh increase in power price$8$37
Coal/Nuclear/Renewable Generation: $2.50/MWh decrease in power price$(4)$(29)
Gas Generation: $1.00/MWh increase in spark spread$12$37
Gas Generation: $1.00/MWh decrease in spark spread$(4)$(30)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$3$(33)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$(3)$28
PJM:
Coal Generation: $2.50/MWh increase in power price$2$5
Coal Generation: $2.50/MWh decrease in power price$—$(2)
Gas Generation: $1.00/MWh increase in spark spread$6$28
Gas Generation: $1.00/MWh decrease in spark spread$(5)$(26)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$(2)$(2)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$2$2
NYISO/ISO-NE:
Gas Generation: $1.00/MWh increase in spark spread$1$8
Gas Generation: $1.00/MWh decrease in spark spread$—$(7)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$2$—
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$(2)$—
MISO/CAISO:
Coal Generation: $2.50/MWh increase in power price$1$21
Coal Generation: $2.50/MWh decrease in power price$—$(21)
Gas Generation: $1.00/MWh increase in spark spread$—$3
Gas Generation: $1.00/MWh decrease in spark spread$—$(3)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price$1$—
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price$(1)$—

(a)Balance of 2020 is from January 1, 2020 through December 31, 2020.

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Competitive Retail Markets and Customer Retention

Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch retail electricity providers for various reasons. Based on numbers of meters and excluding customers acquired in the Ambit and Crius Transactions, our total retail customer counts increased approximately 2% in 2019, 2% in 2018 and slightly in 2017. Based upon December 31, 2019 results discussed below in Results of Operations, a 1% decline in retail customers in ERCOT would result in a decline in annual revenues of approximately $50 million. In responding to the competitive landscape in the ERCOT market, we have attempted to reduce overall customer losses by focusing on the following key initiatives:

  • Maintaining competitive pricing initiatives on residential service plans;

  • Actively competing for new customers in areas open to competition within ERCOT, while continuing to strive to enhance the experience of our existing customers; we are focused on continuing to implement initiatives that deliver world-class customer service and improve the overall customer experience;

  • Establishing and leveraging our TXU EnergyTM brand in the sale of electricity to residential and commercial customers, as the most innovative retailer in the ERCOT market by continuing to develop tailored product offerings to meet customer needs, and

  • Focusing market initiatives largely on programs targeted at retaining the existing highest-value customers and to recapturing customers who have switched REPs, including maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy our direct-sales force; tactical programs we have initiated include improved customer service, aided by an enhanced customer management system, new product price/service offerings and a multichannel approach for the small business market.

Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate generation capacity of 1,150 MW. As of December 31, 2019, these units represented approximately 6% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage at the same time, the unfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2020 at December 31, 2019) to be approximately $2 million per day before consideration of any costs to repair the cause of such outages or receipt of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 13 to the Financial Statements to understand the importance and limits of our insurance protection.

The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review and regulation by the NRC, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs and may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down our Comanche Peak units as a precautionary measure.

We participate in industry groups and with regulators to keep current on the latest developments in nuclear safety, operation and maintenance and on emerging threats and mitigating techniques. These groups include, but are not limited to, the NRC, the Institute of Nuclear Power Operations (INPO) and the Nuclear Energy Institute (NEI). We also apply the knowledge gained through our continuing investment in technology, processes and services to improve our operations and to detect, mitigate and protect our nuclear generation assets. Management continues to focus on the safe, reliable and efficient operations at the facility.

Cyber/Data Security and Infrastructure Protection Risk

A breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could materially affect our reputation, including our TXU EnergyTM, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric brands, expose the company to legal claims or impair our ability to execute on business strategies.

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We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to, the U.S. Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the NRC and NERC.

While the Company has not experienced a cyber/data event causing any material operational, reputational or financial impact, we recognize the growing threat within the general market place and our industry, and are proactively making strategic investments in our perimeter and internal defenses, cyber/data security operations center and regulatory compliance activities. We also apply the knowledge gained through industry and government organizations to continuously improve our technology, processes and services to detect, mitigate and protect our cyber and data assets.

Seasonality

The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results may fluctuate on a seasonal basis. Typically, demand for and the price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme winter weather may make such fluctuations more pronounced. However, not all regions of the U.S. typically experience extreme weather conditions at the same time, so Vistra Energy is typically not exposed to the effects of extreme weather in all parts of its business at once. The pattern of this fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.

Application of Critical Accounting Policies

Our significant accounting policies are discussed in Note 1 to the Financial Statements. We follow accounting principles generally accepted in the U.S. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Purchase Accounting

On November 1, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the Ambit Transaction. On July 15, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the Crius Transaction. The Ambit Transaction and Crius Transaction are being accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on their acquisition dates.

Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

The acquired assets that involved the most subjectivity in determining fair value consisted of the customer relationship intangible assets. The assignment of fair value to the identifiable intangible assets requires judgment. We apply an income-based valuation methodology in measuring the customer relationships acquired, which include certain assumptions such as forecasted future cash flows, customer attrition rates, and discount rates. Customer relationship intangibles assets are generally amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which the economic benefits are realized over their estimated useful lives.

On the Merger Date, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. The Merger was accounted for in accordance with ASC 805, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Merger Date. Vistra Energy is the acquirer for both federal tax and accounting purposes. The combined results of operations are reported in our consolidated financial statements beginning as of the Merger Date. See Note 2 to the Financial Statements.

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The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant and equipment and executory contracts, primarily long-term service agreements for maintenance of power plants, a unit-specific power sales agreement and rail transportation contracts. The fair value of each power plant was estimated using a combination of an income approach and a market approach. The income approach is the present value of future cash flows over the life of each power plant that are based on management’s estimates of revenues and operating expenses, and appropriate discount rates. The estimate of long term prices of electricity and natural gas at each plant location that was used in developing forecasted revenues for the income approach was especially subjective, because as of the Merger Date, limited market information about future prices beyond the year 2022 was available. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the relevant market, with adjustments relating to any differences between the assets and locations. The determination of deferred tax assets was complex as it required assessing income tax rules and regulations and proposed regulations that impose limitations on the future use of acquired net operating losses and other limitations on deductions.

Fresh-Start Reporting

As of the Effective Date, Vistra Energy applied fresh-start reporting under the applicable provisions of ASC 852. Fresh-start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring from the consolidated financial statements of the entity that emerges from restructuring, (2) assigning the reorganized value of the successor entity by measuring all assets and liabilities of the successor entity at fair value, and (3) selecting accounting policies for the successor entity. The effects from emerging from bankruptcy, including the extinguishment of liabilities, as well as the fresh start reporting adjustments are reported in the Predecessor's statement of consolidated income (loss). The consolidated financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of our Predecessor for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities, nor any differences in accounting policies that were a consequence of the Plan of Reorganization or the related application of fresh-start reporting.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. Where quoted market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative instruments valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity, natural gas and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using proprietary modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 15 to the Financial Statements.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. Normal purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the normal purchase or sale election is made. Accounting standards also permit an entity to designate certain qualifying derivative contracts in a hedge accounting relationship, whereby changes in fair value are not recognized immediately in earnings. Vistra Energy does not have derivative instruments with hedge accounting designations.

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We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements that we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that, beginning in January 2017, are legally characterized as settlement of derivative contracts rather than collateral.

See Note 16 to the Financial Statements for further discussion regarding derivative instruments.

Accounting for Income Taxes

Vistra Energy files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra Energy is the corporate parent of the Vistra Energy consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. 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.

Our deferred tax assets were significantly impacted by the TCJA, which reduced the overall federal corporate rate from 35% to 21%. This rate change decreased our overall deferred tax asset balance by approximately $451 million during the year ended December 31, 2017.

See Notes 1 and 7 to the Financial Statements for further discussion of income tax matters.

Accounting for Tax Receivable Agreement

On the Effective Date, Vistra Energy entered into a tax receivable agreement (the TRA) with a transfer agent. Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Vistra Energy reflected the obligation associated with TRA Rights at fair value in the amount of $574 million as of the Emergence Date related to these future payment obligations. As of December 31, 2019, the TRA obligation has been adjusted to $455 million. During the year ended December 31, 2019, we recorded a decrease to the carrying value of the TRA obligation totaling $22 million as a result of adjustments to the timing of forecasted taxable income and state apportionment due to the expansion of Vistra Energy's state income tax profile, including Dynegy, Crius and Ambit acquisitions. At December 31, 2019, expected undiscounted payments under the TRA totaled $1.4 billion. The TRA obligation value is the discounted amount of estimated payments to be made each year under the TRA, based on certain assumptions, including but not limited to:

  • the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo Preferred Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up among the assets subject thereto;

  • the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most of such assets;

  • a blended federal/state corporate income tax rate in all future years of 23.8%;

  • future taxable income by year for future years;

  • the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of (i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise;

  • a discount rate of 15%, which represented our view at the Emergence Date of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence, and

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  • additional states that Vistra Energy now operates in, the relevant tax rates of those states and how income will be apportioned to those states.

We recognize accretion expense over the life of the TRA Rights liability as the present value of the liability is accreted up over the life of the liability. This noncash accretion expense is reported in the consolidated statements of operations as Impacts of Tax Receivable Agreement. Further, there may be significant changes, which may be material, to the estimate of the related liability due to various reasons including changes in federal and state tax laws and regulations, changes in estimates of the amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary book/tax differences and other items. Changes in those estimates are recognized as adjustments to the related TRA Rights liability, with offsetting impacts recorded in the consolidated statements of operations as Impacts of Tax Receivable Agreement. See Note 8 to the Financial Statements.

Asset Retirement Obligations (ARO)

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

During the year ended December 31, 2017, we recorded additional ARO obligations totaling $112 million primarily reflecting the acceleration of ARO obligations due to the retirements of our Monticello, Sandow and Big Brown plants. In addition, we recorded additional ARO obligations in 2017 totaling $62 million as part of acquiring certain real property through the Alcoa contract settlement. During the year ended December 31, 2019, we transferred $135 million in ARO obligations to a third party for remediation. Any remaining unpaid third-party obligation was reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets.

At December 31, 2019, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.320 billion and includes an assumption that Vistra Energy receives a license extension of 20 years from the NRC to continue to operate the Comanche Peak facility. The costs to ultimately decommission that facility are recoverable through the regulatory rate making process as part of Oncor's delivery fees and therefore do not impact Vistra Energy's earnings.

See Note 21 to the Financial Statements for additional discussion of ARO obligations.

Impairment of Goodwill and Other Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. For our generation assets, possible indications include an expectation of continuing long-term declines in natural gas prices and/or market heat rates or an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing. We generally utilize an income approach measurement to derive fair values for our long-lived generation assets. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices. Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets. Additional material impairments related to our generation facilities may occur in the future if forward wholesale electricity prices decline in the markets in which we operate in or if additional environmental regulations increase the cost of producing electricity at our generation facilities.

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Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the TXU EnergyTM, 4Change EnergyTM, Homefield, Dynegy Energy Services, TriEagle Energy, U.S. Gas & Electric, Public Power and Ambit Energy trade names, are required to be tested for impairment at least annually (as of the Effective Date, we have selected October 1 as our annual test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry. Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill is more likely than not less than the fair value of that reporting unit. If the entity determines the carrying value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for impairment is required. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our ERCOT Retail and ERCOT Generation reporting units exceeded its carrying value at October 1, 2019. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition, interest rates and changes in reporting unit book value.

Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2019, $1.960 billion of our goodwill was allocated to our ERCOT Retail reporting unit, $122 million was allocated to our ERCOT Generation reporting unit and $471 million arose in connection with the Ambit and Crius Transactions and is recorded at the retail segment, but has not been allocated to any reporting units and is pending completion of the purchase price allocations, at which time goodwill will be allocated to reporting units. Goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit's assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair value measurements to estimate enterprise values of our reporting units including: internal discounted cash flow analyses (income approach), and comparable publicly traded company values (market approach). The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and retail sales volume trends, as well as determination of a terminal value. Another key variable in the income approach is the discount rate, or weighted average cost of capital, applied to the forecasted cash flows. The determination of the discount rate takes into consideration the capital structure, credit ratings and current debt yields of comparable publicly traded companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. The market approach involves using trading multiples of EBITDA of those selected publicly traded companies to derive appropriate multiples to apply to the EBITDA of our reporting units. Critical judgments include the selection of publicly traded comparable companies and the weighting of the value metrics in developing the best estimate of enterprise value.

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RESULTS OF OPERATIONS

Vistra Energy Consolidated Financial Results — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Year Ended December 31,Favorable (Unfavorable) $ Change
20192018
Operating revenues$11,809$9,144$2,665
Fuel, purchased power costs and delivery fees(5,742)(5,036)(706)
Operating costs(1,530)(1,297)(233)
Depreciation and amortization(1,640)(1,394)(246)
Selling, general and administrative expenses(904)(926)22
Operating income1,9934911,502
Other income56479
Other deductions(15)(5)(10)
Interest expense and related charges(797)(572)(225)
Impacts of Tax Receivable Agreement(37)(79)42
Equity in earnings of unconsolidated investment1617(1)
Income before income taxes1,216(101)1,317
Income tax (expense) benefit(290)45(335)
Net income (loss)$926$(56)$982
Year Ended December 31, 2019
RetailERCOTPJMNY/NEMISOAsset ClosureEliminations / Corporate and OtherVistra Energy Consolidated
Operating revenues$6,872$3,993$2,442$1,135$658$341$(3,632)$11,809
Fuel, purchased power costs and delivery fees(5,816)(1,352)(1,111)(600)(380)(267)3,784(5,742)
Operating costs(71)(714)(328)(101)(150)(138)(28)(1,530)
Depreciation and amortization(292)(508)(537)(208)(19)—(76)(1,640)
Selling, general and administrative expenses(538)(79)(54)(47)(57)(43)(86)(904)
Operating income (loss)1551,34041217952(107)(38)1,993
Other income—28——731856
Other deductions—(8)(1)——(5)(1)(15)
Interest expense and related charges(21)8(10)(3)(4)—(767)(797)
Impacts of Tax Receivable Agreement——————(37)(37)
Equity in earnings of unconsolidated investment——412———16
Income (loss) before income taxes1341,36840518855(109)(825)1,216
Income tax expense——————(290)(290)
Net income (loss)$134$1,368$405$188$55$(109)$(1,115)$926

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Year Ended December 31, 2018
RetailERCOTPJMNY/NEMISOAsset ClosureEliminations / Corporate and OtherVistra Energy Consolidated
Operating revenues$5,597$2,634$1,725$817$399$371$(2,399)$9,144
Fuel, purchased power costs and delivery fees(4,126)(1,521)(917)(485)(174)(286)2,473(5,036)
Operating costs(39)(677)(243)(74)(136)(109)(19)(1,297)
Depreciation and amortization(318)(416)(413)(152)(9)—(86)(1,394)
Selling, general and administrative expenses(424)(90)(52)(36)(31)(39)(254)(926)
Operating income (loss)690(70)1007049(63)(285)491
Other income29341——2(19)47
Other deductions—(7)———(1)3(5)
Interest expense and related charges(7)(12)(8)(2)(1)—(542)(572)
Impacts of Tax Receivable Agreement——————(79)(79)
Equity in earnings of unconsolidated investment——711——(1)17
Income (loss) before income taxes712(55)1007948(62)(923)(101)
Income tax benefit——————4545
Net income (loss)$712$(55)$100$79$48$(62)$(878)$(56)

In 2019, we focused on safe and reliable operations and produced results during the year that exceeded expectations. Our performance reflected the stability of our integrated model with the generation fleet operating reliably over the volatile ERCOT summer while our Retail segment delivered stable pricing and growth in ERCOT residential customer counts. As a result, we generated significant cash from operations, supporting the Company's ability to fund $713 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), invest $880 million in net cash for the Crius and Ambit Transactions, and advance our balanced capital allocation program, refinancing/repricing approximately $8.3 billion of debt, which lowered interest rates and extended maturities, and returning $899 million to stockholders through share repurchases and dividends.

Consolidated results increased $982 million to net income of $926 million in the year ended December 31, 2019 compared to the year ended December 31, 2018. The change in results was driven by a $1.076 billion increase in unrealized gains on hedging transactions, $339 million due to a full year of operations acquired in the Merger, $79 million due to operations acquired in the Crius Transaction and the Ambit Transaction, and $118 million in lower transition and merger expenses; partially offset by $246 million increase in depreciation and amortization, $225 million increase in interest expense and related charges, $335 million increase in income tax expense and $54 million in one-time costs associated with the fourth quarter 2019 plant retirements.

Interest expense and related charges increased $225 million to $797 million in the year ended December 31, 2019 compared to the year ended December 31, 2018 and reflected a $215 million change in unrealized mark-to-market losses on interest rate swaps and a $39 million increase in interest paid/accrued reflecting a full year with increased debt associated with the Merger. Debt extinguishment gains totaled of $21 million in 2019 compared to debt extinguishment losses of $27 million in 2018. See Note 21 to the Financial Statements.

For the years ended December 31, 2019 and 2018, the Impacts of the TRA totaled expense of $37 million and $79 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA Obligation.

For the year ended December 31, 2019, income tax expense totaled $290 million and the effective tax rate was 23.8%. For the year ended December 31, 2018, income tax benefit totaled $45 million and the effective tax rate was 44.6%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

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Consolidated cash flow from operations produced $2.736 billion in the year ended December 31, 2019 compared to $1.471 billion produced in the year ended December 31, 2018.

Discussion of Adjusted EBITDA

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

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

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

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

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Adjusted EBITDA — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Year Ended December 31,Favorable (Unfavorable) $ Change
20192018
Net income (loss)$926$(56)$982
Income tax expense (benefit)290(45)335
Interest expense and related charges (a)797572225
Depreciation and amortization (b)1,7131,472241
EBITDA3,7261,9431,783
Unrealized net (gain) loss resulting from hedging transactions(696)380(1,076)
Generation plant retirement expenses54—54
Fresh start/purchase accounting impacts3041(11)
Impacts of Tax Receivable Agreement3779(42)
Non-cash compensation expenses4873(25)
Transition and merger expenses115233(118)
Other, net11(7)18
Adjusted EBITDA, including Odessa earnout buybacks$3,325$2,742$583
Odessa earnout buybacks—18(18)
Adjusted EBITDA$3,325$2,760$565

(a)Includes unrealized mark-to-market net losses on interest rate swaps of $220 million and $5 million for the years ended December 31, 2019 and 2018, respectively.

(b)Includes nuclear fuel amortization in the ERCOT segment of $73 million and $78 million for the years ended December 31, 2019 and 2018, respectively.

Year Ended December 31, 2019
RetailERCOTPJMNY/NEMISOAsset ClosureEliminations / Corporate and OtherVistra Energy Consolidated
Net income (loss)$134$1,368$405$188$55$(109)$(1,115)$926
Income tax expense——————290290
Interest expense and related charges (a)21(8)1034—767797
Depreciation and amortization (b)29258153720819—761,713
EBITDA4471,94195239978(109)183,726
Unrealized net (gain) loss resulting from hedging transactions278(591)(203)(109)(30)—(41)(696)
Generation plant retirement expenses————1242—54
Fresh start/purchase accounting impacts23(3)(2)415(3)(4)30
Impacts of Tax Receivable Agreement——————3737
Non-cash compensation expenses——————4848
Transition and merger expenses49116421—24115
Other, net10127972(36)11
Adjusted EBITDA$807$1,370$760$307$103$(68)$46$3,325

(a)Includes $220 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $73 million in the ERCOT segment.

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Year Ended December 31, 2018
RetailERCOTPJMNY/NEMISOAsset ClosureEliminations / Corporate and OtherVistra Energy Consolidated
Net income (loss)$712$(55)$100$79$48$(62)$(878)$(56)
Income tax benefit——————(45)(45)
Interest expense and related charges (a)712821—542572
Depreciation and amortization (b)3184944131529—861,472
EBITDA1,03745152123358(62)(295)1,943
Unrealized net (gain) loss resulting from hedging transactions(206)4984240(9)—15380
Fresh start/purchase accounting impacts26(6)(1)9121—41
Impacts of Tax Receivable Agreement——————7979
Non-cash compensation expenses——————7373
Transition and merger expenses1914292196233
Other, net(13)(2)16910(4)(23)(7)
Adjusted EBITDA, including Odessa earnout buybacks84595059229380(63)452,742
Odessa earnout buybacks1818
Adjusted EBITDA$845$968$592$293$80$(63)$45$2,760

(a)Includes $5 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $78 million in the ERCOT segment.

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Retail Segment — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Year Ended December 31,Favorable (Unfavorable) Change
20192018
Operating revenues:
Revenues in ERCOT$5,061$4,512$549
Revenues in Northeast/Midwest1,8181,123695
Amortization expense(15)(26)11
Other revenues8(12)20
Total operating revenues$6,872$5,597$1,275
Fuel, purchased power costs and delivery fees:
Purchases from affiliates(3,571)(2,846)(725)
Unrealized net gains (losses) on hedging activities with affiliates(305)218(523)
Unrealized net gains (losses) on hedging activities19—19
Delivery fees(1,629)(1,493)(136)
Other costs (a)(330)(5)(325)
Total fuel, purchased power costs and delivery fees$(5,816)$(4,126)$(1,690)
Net income (loss)$134$712$(578)
Adjusted EBITDA$807$845$(38)
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT47,34542,9924,353
Sales volumes in Northeast/Midwest30,25520,7399,516
Total retail electricity sales volumes77,60063,73113,869
Weather (North Texas average) - percent of normal (b):
Cooling degree days96.0%103.0%
Heating degree days113.0%112.0%

(a)For the year ended December 31, 2019, includes $329 million of third-party power purchases, primarily related to the recent Ambit and Crius Transactions.

(b)Weather data is obtained from Weatherbank, Inc. For the year ended December 31, 2019, normal is defined as the average over the 10-year period from December 2009 to December 2018. For the year ended December 31, 2018, normal is defined as the average over the 10-year period from December 2008 to December 2017.

Net income decreased by $578 million to $134 million and Adjusted EBITDA decreased by $38 million to $807 million in the year ended December 31, 2019 compared to the year ended December 31, 2018.

Unfavorable margins in ERCOT driven by increased power costs and timing of multi-year retail contracts due to backwardation of power curves$(45)
Impact of Crius acquired in July 2019 and Ambit acquired in November 201979
Unfavorable weather in ERCOT(34)
Other driven by higher bad debt expense and other SG&A expense(38)
Change in Adjusted EBITDA$(38)
Change in depreciation and amortization expenses driven by reduced amortization of the retail customer relationship29
Unfavorable impact of unrealized net losses on hedging activities(484)
Higher transition and merger and other expenses(85)
Change in Net income$(578)

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Generation — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Year Ended December 31,
ERCOTPJMNY/NEMISO
20192018201920182019201820192018
Operating revenues:
Electricity sales$1,205$1,289$1,122$775$703$582$342$275
Capacity——1623691812392425
Sales to affiliates2,2131,82992162815344285100
Rolloff of unrealized net gains (losses) representing positions settled in the current period3714041644—5(31)14
Unrealized net gains (losses) on hedging activities72(689)68(61)75(42)62(27)
Unrealized net gains (losses) on hedging activities with affiliates132(198)153(33)27(3)(7)16
Other revenues—(1)—3(4)(8)(17)(4)
Operating revenues3,9932,6342,4421,7251,135817658399
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs(1,186)(1,367)(1,073)(916)(597)(479)(380)(203)
Fuel for generation facilities and purchased power costs from affiliates——(1)(8)(1)—230
Unrealized (gains) losses from hedging activities16(15)(34)87—66
Ancillary and other costs(182)(139)(3)(1)(9)(6)(8)(7)
Fuel, purchased power costs and delivery fees(1,352)(1,521)(1,111)(917)(600)(485)(380)(174)
Net income (loss)$1,368$(55)$405$100$188$79$55$48
Adjusted EBITDA$1,370$968$760$592$307$293$103$80
Production volumes (GWh):
Natural gas facilities39,43335,79037,40326,43118,15214,605
Lignite and coal facilities27,74329,15114,06714,10217,17212,724
Nuclear facilities19,30520,416
Solar/Battery facilities439344
Capacity factors:
CCGT facilities55.0%58.8%70.1%67.8%43.8%48.2%
Lignite and coal facilities70.4%76.9%46.1%63.2%61.5%62.3%
Nuclear facilities95.8%101.3%
Weather - percent of normal (a):
Cooling degree days99%100%110%122%100%118%110%134%
Heating degree days111%113%99%103%102%103%99%97%
Market pricing
Average ERCOT North power price ($/MWh)$35.93$29.96

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Year Ended December 31,
ERCOTPJMNY/NEMISO
20192018201920182019201820192018
Average NYMEX Henry Hub natural gas price ($/MMBtu)$2.51$3.12
Average Market On-Peak Power Prices ($MWh) (b):
PJM West Hub$30.87$41.79
AEP Dayton Hub$31.02$40.47
NYISO Zone C$25.90$37.03
Massachusetts Hub$34.89$50.11
Indiana Hub$31.23$39.01
Northern Illinois Hub$28.16$34.46
Average natural gas price (c):
TetcoM3 ($/MMBtu)$2.39$3.69
Algonquin Citygates ($/MMBtu)$3.17$4.84

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

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

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

The following table presents changes in net income and Adjusted EBITDA for the year ended December 31, 2019 compared to the year ended December 31, 2018.

Year Ended December 31, 2019 Compared to 2018
ERCOTPJMNY/NEMISO
Favorable impact related to operations acquired in the Merger (a)$—$201$86$56
Favorable/(unfavorable) change in revenue net of fuel438(20)(63)(62)
Favorable/(unfavorable) change in other operating costs(39)(4)(2)31
Favorable/(unfavorable) change in selling. general and administrative expenses9(4)(3)(3)
Other(6)(5)(4)1
Change in Adjusted EBITDA$402$168$14$23
Unfavorable change in depreciation and amortization(87)(124)(56)(10)
Unrealized net gains on hedging activities1,08924514921
Fresh start/purchase accounting impacts(3)15(3)
Transition and merger expenses(2)8(2)(12)
Generation plant retirement expenses———(12)
Other (including interest)247(1)—
Change in Net income$1,423$305$109$7

(a)Impact related to PJM, NY/NE and MISO operations acquired in the Merger are the combined results for the first quarter of 2019, for which there is no comparable period for 2018 due to the Merger date of April 9, 2018.

The change in ERCOT segment results was driven by a $438 million increase in generation revenue net of fuel reflecting higher realized power prices, lower natural gas fuel costs and a 1,219 GWh increase in total production volumes, partially driven by the first quarter production of the generation facilities acquired in the Merger.

The change in PJM segment results was driven by $201 million related to operations in the first quarter of 2019 acquired in the Merger, partially offset by lower generation in the second through fourth quarters.

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The change in NY/NE segment results was driven by $86 million related to operations in the first quarter of 2019 acquired in the Merger, partially offset by lower generation in the second through fourth quarters.

The change in MISO segment results was driven by $52 million related to operations in the first quarter of 2019 acquired in the Merger and a $30 million decrease in operating costs during the second through fourth quarters, partially offset by a $57 million decrease in revenue net of fuel during the second through fourth quarters reflecting lower realized power prices and capacity revenue.

Asset Closure Segment — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Year Ended December 31,Favorable (Unfavorable) Change
20192018
Operating revenues$341$371$(30)
Fuel, purchased power costs and delivery fees(267)(286)19
Operating costs(138)(109)(29)
Selling, general and administrative expenses(43)(39)(4)
Operating income (loss)(107)(63)(44)
Other income321
Other deductions(5)(1)(4)
Net income (loss)$(109)$(62)$(47)
Adjusted EBITDA$(68)$(63)$(5)
Production volumes (GWh)7,4849,759(2,275)

Results for the Asset Closure segment reflect the retirement of the Coffeen, Duck Creek, Havana and Hennepin plants in November and December 2019, the retirement of the Northeastern waste coal plant in October 2018, retirement of the Stuart and Killen plants in May 2018 (acquired in the Merger) and the retirement of the Monticello, Sandow and Big Brown plants in January and February 2018 (see Note 4 to the Financial Statements). Operating costs for the years ended December 31, 2019 and 2018 included ongoing costs associated with closing these plants.

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

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2019 and 2018. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $696 million in unrealized net gains for the year ended December 31, 2019 and $380 million in unrealized net losses for the year ended December 31, 2018, all arising from mark-to-market accounting for positions in the commodity contract portfolio.

Year Ended December 31,
20192018
Commodity contract net liability at beginning of period$(850)$(96)
Settlements/termination of positions (a)358457
Changes in fair value of positions in the portfolio (b)338(837)
Acquired commodity contracts (c)(28)(454)
Other activity (d)(97)80
Commodity contract net liability at end of period$(279)$(850)

(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The years ended December 31, 2019 and 2018 include reversals of $3 million and $17 million of previously recorded unrealized gains related to Vistra Energy beginning balances. The years ended December 31, 2019 and 2018 also include reversals of $124 million and $320 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius Acquisition and Ambit Acquisition. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(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 on the Crius Acquisition, Ambit Acquisition in 2019 and on the Merger Date in 2018 (see Note 2 to the Financial Statements).

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

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at December 31, 2019, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

Maturity dates of unrealized commodity contract net liability at December 31, 2019
Source of fair valueLess than 1 year1-3 years4-5 yearsExcess of 5 yearsTotal
Prices actively quoted$74$(8)$(4)$—$62
Prices provided by other external sources(269)2——(267)
Prices based on models29(22)(6)(75)(74)
Total$(166)$(28)$(10)$(75)$(279)

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FINANCIAL CONDITION

Operating Cash Flows

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 — Cash provided by operating activities totaled $2.736 billion and $1.471 billion in the years ended December 31, 2019 and 2018, respectively. The favorable change of $1.265 billion was primarily driven by increased cash from operations reflecting operations acquired in the Merger, favorable operating results in the ERCOT segment and a decrease in cash used for margin deposits posted with third-parties.

Depreciation and Amortization — Depreciation and amortization expense reported as a reconciling adjustment in the consolidated statements of cash flows exceeds the amount reported in the consolidated statements of operations by $236 million, $139 million and $136 million for the year ended December 31, 2019, 2018 and 2017, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees.

Investing Cash Flows

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 — Cash used in investing activities totaled $1,717 million and $101 million in the years ended December 31, 2019 and 2018, respectively. Capital expenditures (including LTSA prepayments, nuclear fuel purchases and growth and development expenditures) totaled $713 million and $530 million in the years ended December 31, 2019 and 2018, respectively. Cash used in investing activities in the year ended December 31, 2019 also reflected $880 million of net cash paid in the Crius and Ambit Transactions and $125 million of net purchases of environmental allowances. Cash used in investing activities in the year ended December 31, 2018 also reflected $445 million of cash acquired in the Merger.

In the years ended December 31, 2019 and 2018, capital expenditures, including LTSA prepayments, nuclear fuel purchases and growth and development expenditures, consisted of:

Year Ended December 31,
20192018
Investments in generation and mining facilities$333$208
Nuclear fuel purchases89118
LTSA prepayments122100
Information technology and other corporate investments (a)6570
Growth and development expenditures10434
Capital expenditures, including LTSA prepayments, nuclear fuel purchases and growth and development expenditures$713$530

(a)Includes Comanche Peak repair costs.

Financing Cash Flows

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 — Cash used in financing activities totaled $1.237 billion and $2.723 billion in the years ended December 31, 2019 and 2018, respectively. The decrease in cash used in financing activities was driven by:

  • the issuance of $5.7 billion principal amount of Vistra Operations senior secured and unsecured notes in 2019 compared to the issuance of $1.0 billion principal amount of Vistra Operations senior unsecured notes in 2018;

  • the amendment to the Vistra Operations Credit Facilities in 2018, including the repayment of $500 million in term loans;

  • $350 million in net borrowings under the Revolving Credit Facility in 2019, and;

  • $107 million decrease in cash paid for share repurchases in 2019 compared to 2018,

partially offset by:

  • the net repayment of approximately $3.1 billion of term loans under the Vistra Operations Credit Facilities in 2019;

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  • cash tender offers and early redemptions to purchase senior unsecured notes assumed in the Merger of $3.0 billion in 2019 compared to $2.5 billion in 2018;

  • $243 million of cash dividends paid to stockholders in 2019, and

  • $228 million net decrease in incremental borrowings under the account receivable securitization program.

Debt Activity

See Note 11 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the year ended December 31, 2019:

December 31, 2019December 31, 2018Change
Cash and cash equivalents$300$636$(336)
Vistra Operations Credit Facilities — Revolving Credit Facility1,4261,135291
Total available liquidity$1,726$1,771$(45)

The $45 million decrease in available liquidity in the year ended December 31, 2019 was primarily driven by $880 million of net cash paid in the Crius and Ambit Transactions, $656 million in cash paid for share repurchases, $713 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), $387 million principal amount of outstanding 7.625% Senior Notes due 2024 redeemed in November 2019, $243 million in dividends paid to shareholders, $203 million in debt tender offer and other financing fees and the $70 million redemption of mandatorily redeemable preferred stock in PrefCo, partially offset by cash from operations, $500 million of new Alternate LOC Facilities and $225 million of additional available capacity under the Revolving Credit Facility.

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

Capital Expenditures

Estimated capital expenditures and nuclear fuel purchases for 2020 are expected to total approximately $935 million and include:

  • $532 million for investments in generation and mining facilities;

  • $85 million for nuclear fuel purchases;

  • $3 million for information technology and other corporate investments, and

  • $315 million for growth and development expenditures.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 11 to the Financial Statements for discussion of the Vistra Operations Credit Facilities.

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

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At December 31, 2019, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:

  • $202 million in cash has been posted with counterparties as compared to $361 million posted at December 31, 2018;

  • $8 million in cash has been received from counterparties as compared to $4 million received at December 31, 2018;

  • $1.150 billion in letters of credit have been posted with counterparties as compared to $1.185 billion posted at December 31, 2018, and

  • $17 million in letters of credit have been received from counterparties as compared to $12 million received at December 31, 2018.

Income Tax Payments

In the next 12 months, we do not expect to make federal income tax payments due to Vistra Energy's use of NOL carryforwards. We expect to make approximately $26 million in state income tax payments, offset by $14 million in state tax refunds, and no TRA payments in the next 12 months. In addition, we expect to receive approximately $100 million in AMT refundable credits in the next 12 months.

In February 2019, we received a refund of $21 million related to Vistra Energy's 2017 federal tax return. In December 2019, we received a refund of $94 million related to alternative minimum tax credits claimed on Vistra Energy's 2018 tax return. For the year ended December 31, 2019, there were no federal income tax payments, $39 million in state income tax payments and $2 million in TRA payments.

Capitalization

Our capitalization ratios consisted of 56% and 58% long-term debt (less amounts due currently) and 44% and 42% shareholders' equity at December 31, 2019 and 2018, respectively. Total long-term debt (including amounts due currently) to capitalization was 57% and 58% at December 31, 2019 and 2018, respectively.

Financial Covenants

The Credit Facilities Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not exceed 4.25 to 1.00. As of December 31, 2019, we were in compliance with this financial covenant.

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

Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at December 31, 2019, Vistra Energy has posted letters of credit in the amount of $38 million with the PUCT, which is subject to adjustments.

The RTOs/ISOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those RTOs/ISOs. Under these rules, Vistra Energy has posted collateral support totaling $316 million in the form of letters of credit, $10 million in the form of a surety bond and $8 million of cash at December 31, 2019 (which is subject to daily adjustments based on settlement activity with the RTOs/ISOs).

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Material Cross Default/Acceleration Provisions

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

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances (approximately $3.05 billion at December 31, 2019, including $350 million of cash borrowings under the Revolving Credit Facility) under such facilities.

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

Under (i) the Vistra Operations' Senior Unsecured Indentures and the Senior Secured Indenture, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, or (ii) with respect to the Vistra Energy Senior Unsecured Indentures (except with respect to the Consent Senior Notes), a default under any document evidencing indebtedness for borrowed money by Vistra Energy or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $100 million or more, may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Energy Senior Unsecured Notes (except with respect to the Consent Senior Notes), the Vistra Operations Credit Facilities, the Receivables Facility, the Alternate LOC Facilities, and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

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

The Receivables Facility contains a cross default provision. The cross default provision applies, among other instances, if Vistra Operations, the performance guarantor, fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, or, in the case of TXU Energy, the originator and servicer, in a principal amount of at least $50 million, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated.

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

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Contractual Obligations and Commitments

The following table summarizes the amounts and related maturities of our contractual cash obligations at December 31, 2019. See Notes 11 and 13 to the Financial Statements for additional disclosures regarding debt and noncancellable purchase obligations.

Contractual Cash Obligations:Less Than One YearOne to Three YearsThree to Five YearsMore Than Five YearsTotal
Debt – principal (a)$273$136$2,076$7,949$10,434
Debt – interest5029679549123,335
Operating and finance leases29423682189
Long-term service and maintenance contracts1673243131,9752,779
Obligations under commodity purchase and services agreements (b)1,3787337099743,794
Total contractual cash obligations$2,349$2,202$4,088$11,892$20,531

(a)Includes $2.7 billion principal amount of term loans under the Vistra Operations Credit Facility, $3.1 billion principal amount of Vistra Operations senior secured notes, $3.6 billion principal amount of Vistra Operations senior unsecured notes, $747 million principal amount of Vistra Energy senior unsecured notes and $287 million principal amount of other long-term debt, including forward capacity agreements and equipment financing agreements. Excludes short-term borrowings, the accounts receivable securitization program and unamortized premiums, discounts and debt costs.

(b)Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the year-end 2019 price for all periods except where contractual price adjustment or index-based prices are specified.

The following are not included in the table above:

  • the TRA obligation (see Note 8 to the Financial Statements);

  • asset retirement obligations (see Note 21 to the Financial Statements);

  • arrangements between affiliated entities and intercompany debt (see Note 19 to the Financial Statements);

  • individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);

  • contracts that are cancellable without payment of a substantial cancellation penalty, and

  • employment contracts with management.

Guarantees

See Note 13 to the Financial Statements for discussion of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

As of December 31, 2019, we have no off-balance sheet arrangements, other than certain investments in energy and energy-related entities that are accounted for under the equity method of accounting which are not expected to have any material impact on our financial condition, results of operations or liquidity.

COMMITMENTS AND CONTINGENCIES

See Note 13 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

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

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