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Item 7. Management’s Discussion and Analysis

2021-02-23 compared with 2020-02-20 · 401 added, 255 removed, 263 unchanged (71% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Report.

The following discussion and analysis of our financial condition, results of operations and cash flow should be read in conjunction with our consolidated financial statements and related notes and with the statistical information and financial data included elsewhere in this Report.

References to CVR Energy, the Company, “we,” “us,” and “our” may refer to consolidated subsidiaries of CVR Energy, including CVR Refining or CVR Partners, as the context may require.

This discussion and analysis generally discusses the years ended December 31, 2019 and 2018 and year-to-year comparisons between such periods.

The discussions of the year ended December 31, 2017 and year-to-year comparisons between the years ended December 31, 2018 and 2017 that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on June 12, 2019, and such discussion are incorporated by reference into this Report.

This discussion and analysis covers the years ended December 31, 2020 and 2019 and discusses year-to-year comparisons between such periods.

The discussions of the year ended December 31, 2018 and year-to-year comparisons between the years ended December 31, 2019 and 2018 that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed on February 20, 2020, and such discussions are incorporated by reference into this Report.

Reflected in this discussion and analysis is how management views the Company’s current financial condition and results of operations along with key external variables and management’s actions that may impact the Company.

Understanding significant external variables, such as market conditions, weather, and seasonal trends, among others, and management actions taken to manage the Company, address external variables, among others, which will increase users’ understanding of the Company, its financial condition and results of operations.

This discussion may contain forward looking statements that reflect our plans, estimates and beliefs.

Our actual results could differ materially from those discussed in the forward looking statements.

Factors that could cause or contribute to such differences include, but are not limited to those discussed below and elsewhere in this Report.

Strategy and Goals

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• Continuous Improvement - We believe in both individual and team success.

We foster accountability under a performance-driven culture that supports creative thinking, teamwork and personal development so that employees can realize their maximum potential.

We foster accountability under a performance-driven culture that supports creative thinking, teamwork, diversity and personal development so that employees can realize their maximum potential.

We use defined work practices for consistency, efficiency and to create value across the organization.

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Our core values are driven by our people, inform the way we do business each and every day and enhance our ability to accomplish our mission and related strategic objectives.

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Safety - We aim to achieve continuous improvement in all environmental, health and safety areas through ensuring our people’s commitment to environmental, health and safety comes first, the refinement of existing policies, continuous training, and enhanced monitoring procedures.

Reliability - Our goal is to achieve industry-leading utilization factors at our facilities through safe and reliable operations.

We are focusing on improvements in day-to-day plant operations, identifying alternative sources for plant inputs to reduce lost

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time due to third-party operational constraints, and optimizing our commercial and marketing functions to maintain plant operations at their highest level.

Market Capture - We continuously evaluate opportunities to improve the facilities’ netbacks and reduce variable costs incurred in production to maximize our capture of market opportunities.

Financial Discipline - We strive to be as efficient as possible by maintaining low operating costs and a disciplined deployment of capital.

We successfully executed a number of achievements in support of our strategic objectives shown below through the date of this filing:

Reliability - Our goal is to achieve industry-leading utilization rates at our Facilities through safe and reliable operations.

We are focusing on improvements in day-to-day plant operations, identifying alternative sources for plant inputs to reduce lost time due to third-party operational constraints, and optimizing our commercial and marketing functions to maintain plant operations at their highest level.

Market Capture - We continuously evaluate opportunities to improve the facilities’ realized pricing at the gate and reduce variable costs incurred in production to maximize our capture of market opportunities.

Financial Discipline - We strive to be as efficient as possible by maintaining low operating costs and disciplined deployment of capital.

We successfully executed a number of achievements in support of our strategic objectives shown below through the date of this filing despite the challenges experienced by the industry during 2020 as a result of the COVID-19 pandemic:

Safety Reliability Market Capture Financial Discipline

Achieved year over year environment, health, and safety improvements related to total recordable incident rate, environmental events, and project safety management of 11%, 14%, and 50%, respectively.

Declared cash dividends of $3.05 per share in 2019.

Announced $300 million share repurchase authorization.

Issued $1.0 billion in Senior Notes due 2025 and 2028 and the associated funding of the redemption of the CVR Refining Senior Notes due 2022 in January 2020.

Increased liquidity and extended debt maturity with the January issuance of $1.0 billion of Senior Unsecured Notes due in 2025 and 2028, and the redemption of $0.5 billion CVR Refining Senior Notes due in 2022.

Operated our Petroleum Segment and Nitrogen Fertilizer Segment facilities safely and reliably and maintained financial discipline amid COVID-19 pandemic.

Reduced consolidated operating and SG&A expenses by over 12% compared to 2019.

Reduced lost profit opportunities by $46 million compared to 2019.

Achieved over 19% reduction in environmental events compared to 2019.

Reduced capital spending by over $21 million compared to initial spending plans.

Petroleum Segment:

Completed the Wynnewood turnaround safely, on time and under budget.

Increased throughput of regional crudes and condensate by 37% and 58%, respectively, while reducing reliance on WTI Cushing common crude oil by 35% for the fourth quarter 2019 as compared to the fourth quarter 2018.

Completed the Wynnewood refinery’s BenFree repositioning project enabling increased premium gasoline production.

Completed the sale of the Cushing, Oklahoma crude oil terminal.

Maintained high utilization at both facilities through the fourth quarter of 2019.

Received Board approval for the Isomerization project at the Wynnewood Refinery, intended to improve liquid yields.

Nitrogen Fertilizer:

Safely completed the East Dubuque turnaround.

Maintained high asset reliability and utilization at both facilities through the fourth quarter of 2019 (adjusted for turnaround at East Dubuque).

Paid cash distributions of 40 cents per unit in 2019.

Safely completed the planned turnaround of the Coffeyville Refinery in April 2020, limiting exposure to the volatile margin environment.

Received Board approval to proceed with construction of the Renewable Diesel Unit (“RDU”) project at the Wynnewood Refinery.

Announced agreement to acquire Oklahoma crude oil pipeline business from Blueknight Energy.

Reduced operating and SG&A expenses by 13% compared to 2019.

Reduced lost profit opportunities by $32 million compared to 2019.

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Safety Reliability Market Capture Financial Discipline

Reduced capital spending by $20 million compared to initial spending plans.

Achieved over 40% reduction in environmental events compared to 2019.

Nitrogen Fertilizer:

Maintained high asset reliability and a combined utilization rate of 98% at both facilities through the fourth quarter of 2020.

Achieved record shipments of ammonia from the East Dubuque Fertilizer Facility during April 2020.

Reduced lost profit opportunities by $14 million compared to 2019.

Generated Coffeyville Fertilizer Facility’s first carbon offset credits related to N 2 O abatement and continued sequestration of CO 2 for enhanced crude oil recovery.

Reduced operating and SG&A expenses by over 12% in 2020 as compared to 2019.

Reduced capital spending by $9 million compared to initial spending plans.

Amended and extended the Nitrogen Fertilizer ABL during the third quarter of 2020.

Completed Messer contract renewal with favorable conditions including new O 2 tank.

Repurchased $7 million of CVR Partners common units during 2020.

Industry Factors and Market Conditions

General Business Environment

In March 2020, the World Health Organization categorized COVID-19 as a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency.

The COVID-19 pandemic and actions taken by governments and others in response thereto has negatively impacted the worldwide economy, financial markets, and the energy and fertilizer industries.

The COVID-19 pandemic has also resulted in significant business and operational disruptions, including business closures, liquidity strains, destruction of non-essential demand, as well as supply chain challenges, travel restrictions, stay-at-home orders, and limitations on the availability of the workforce.

Actions taken by the U.S.

government to provide stimulus to individuals and businesses have helped mitigate the short-term impacts of the downturn caused by COVID-19.

Vaccination efforts underway domestically and internationally also provide promise for near-term economic recovery.

However, it is too early to determine the extent or timing by which the stimulus and vaccinations along with other government actions will benefit the overall business environment in the long-term.

Petroleum Segment

The earnings and cash flows of the Petroleum Segment are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products.

The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond the Petroleum Segment’s control, including the supply of and demand for crude oil, as well as, gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation.

The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond the Petroleum Segment’s control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, driving habits, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation.

Because the Petroleum Segment applies first-in first-out accounting to value its inventory, crude oil price movements may impact net income in the short term because of changes in the value of its unhedged inventory.

The effect of changes in crude oil prices on the Petroleum Segment results of operations is partially influenced by the rate at which the process of refined products adjust to reflect these changes.

The prices of crude oil and other feedstocks and refined products are also affected by other factors, such as product pipeline capacity, system inventory local market conditions and the operating levels of competing refineries.

Crude oil costs and the prices of refined products have historically been subject to wide fluctuations.

The prices of crude oil and other feedstocks and refined products are also affected by other factors, such as product pipeline capacity, system inventory, local market conditions, and the operating levels of other refineries.

Crude oil costs and the prices

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of refined products have historically been subject to wide fluctuations.

Widespread expansion or upgrades of competitors’ facilities, price volatility, international political and economic developments, and other factors are likely to continue to play an important role in refining industry economics.

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Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for volatile seasonal exports of diesel from the United States Gulf Coast markets.

In addition to current market conditions, there are long-term factors that may impact the demand for refined products.

These factors include mandated renewable fuels standards, proposed climate change laws and regulations and increased mileage standards for vehicles.

The petroleum business is also subject to the renewable fuel standards (“RFS”) of the EPA, which requires blending “renewable fuels” with transportation fuels or purchase renewable identification numbers (“RINs”), in lieu of blending, by March 31, 2019 or otherwise be subject to penalties.

Our cost to comply with RFS is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period.

Based upon recent market prices of RINs and current estimates related to the other variable factors, our estimated cost to comply with RFS is $100 to $110 million for 2020.

2019 Market Conditions

As a result of the government actions taken to curb the spread of COVID-19 and significant business interruptions observed, the demand for gasoline and diesel in the regions in which our Petroleum segment operates declined 10% for the year ending December 31, 2020 versus the same period in 2019.

Significant demand destruction was observed into the late summer, however, as government restrictions have been eased, demand has improved modestly in the second half of 2020.

Throughout 2020, fundamental changes have occurred across the U.S.

market as gasoline demand remains approximately 1 million barrels per day lower than 2019 due to a decrease in vehicle miles driven, jet fuel demand has declined significantly due to reductions in air travel for both business and leisure, which in turn, has resulted in reduced diesel crack spreads, and crude oil and refined product inventories remain in focus given current demand indicators.

As a result of these market changes, a number of refinery closures totaling approximately 5 million barrels per day globally (approximately 1 million barrels per day in the U.S.) have been announced.

Potential exists for further capacity rationalization as demand remains at or below current levels, and given the lower crack spread environment, refineries are competing primarily on operating costs per barrel.

In addition to current market conditions discussed above, we have experienced significant volatility during 2020 and expect continued volatility in 2021 due to compliance requirements under the RFS, proposed climate change laws and regulations, and increased mileage standards for vehicles.

The petroleum business is subject to the RFS, which, each year, requires blending “renewable fuels” with transportation fuels or purchasing renewable identification numbers (“RINs”), in lieu of blending, or otherwise be subject to penalties.

Our cost to comply with the RFS is dependent upon a variety of factors, which include the availability of ethanol for blending at our refineries and downstream terminals or RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, and the mix of our products, all of which can vary significantly from period to period.

Additionally, our costs to comply with the RFS depend on the consistent and timely application of the program by the EPA, such as timely establishment of annual renewable volume obligation (“RVO”).

Due to recent uncertainty resulting from the ruling of the U.S.

Court of Appeals for the 10th Circuit, (the “10th Circuit”) in January 2020 relating to small refinery exemptions under the RFS, recent broad rejections of waiver requests by the EPA, delays in establishing the 2021 RVO, and the recent change in administration, we have experienced significant volatility in the price of RINs and as a result, our costs to comply with RFS have increased significantly compared to 2019.

Supreme Court is currently slated to review the 10th Circuit’s decision in April 2021, which could materially impact the price of RINs and existing waiver applications we have submitted for 2019 and 2020 related to our Wynnewood Refinery.

In December 2020, our Board of Directors approved the renewable diesel project at our Wynnewood Refinery, which would convert the Wynnewood Refinery’s hydrocracker to a renewable diesel unit capable of producing 100 million gallons of renewable diesel per year (the “RDU”) and approximately 170 to 180 million RINs annually.

Total estimated costs for the project are currently $110 million and completion of the RDU is expected in June 2021.

As a result of conversion of the hydrocracker to RDU service, the crude oil capacity of the Wynnewood Refinery would be reduced by approximately 17,000 bpd to 57,500 bpd.

The production of renewable diesel and reduction to our crude oil throughput is expected to significantly reduce our net exposure to the RFS.

Further, the RDU enables us to capture additional benefits associated with the existing blenders’ tax credit currently set to expire at the end of 2022 and low carbon fuel standard programs in states such as California.

We have additional plans to add pretreating capabilities for the RDU at Wynnewood and construction of a similar facility at our Coffeyville Refinery subject to Board and other approvals.

These collective renewable diesel efforts could effectively mitigate our RFS exposure.

However, actions taken by the Supreme Court, resulting administration efforts under the RFS, such as denial of existing or previous waiver applications, and market conditions could significantly impact the amount by which our renewable diesel business mitigates our costs to comply with the RFS.

As of December 31, 2020, with the unknown resolution of items discussed above, we have an open obligation under the RFS for 2020 of approximately 240 million RINs, which was subsequently reduced to 221 million RINs as of January 2021.

Under accounting rules, the open RFS obligation is marked-to-market each period and thus can result in significant volatility in our RFS expense from period to period.

We recognized an expense of approximately $190 million, $43 million, and $60 million for the years ended December 31, 2020, 2019, and 2018, respectively, for the Petroleum Segment’s compliance with the RFS.

The increase in 2020 was driven primarily by the significant increases in RINs pricing, especially during the fourth quarter of 2020, and our open position with respect to the 2020 obligation.

Based upon recent market prices of RINs, current estimates related to other variable factors, including our anticipated blending and purchasing activities, and the impact of the open 2020

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obligation and resolution thereof, our estimated cost to comply with the RFS is $260 to $280 million for 2021, net of the estimated RINs credit generation from renewable diesel operations of $95 to $105 million.

Market Indicators

NYMEX WTI crude oil is an industry wide benchmark that is utilized in the market pricing of a barrel of crude oil.

Other crude oils that are compared to WTI, known as differentials, show how the market for other crude oils such as WCS, White Cliffs (“Condensate”), Brent Crude (“Brent”), and Midland WTI (“Midland”) are trending.

During 2019, there were price fluctuations within these differentials due to the continued curtailments imposed by the Alberta government, therefore, tightening the WCS to WTI differential.

Additionally, there have been start-up and line fill of new pipelines from West Texas to the Gulf Coast further tightening the domestic differentials against WTI.

As a performance benchmark and a comparison with other industry participants, we utilize the NYMEX and the Mid-Continent crack spreads.

These crack spreads are a measure of the difference between market prices for crude oil and refined products and is a commonly used proxy within the industry to estimate or identify trends in refining margins.

The pricing differences between other crudes and WTI, known as differentials, show how the market for other crude oils such as WCS, White Cliffs (“Condensate”), Brent Crude (“Brent”), and Midland WTI (“Midland”) are trending.

Due to the COVID-19 pandemic, actions taken by governments and others in response thereto, refined product prices have experienced extreme volatility.

As a result of the current environment, refining margins have been and could continue to be significantly reduced.

As a performance benchmark and a comparison with other industry participants, we utilize NYMEX and Group 3 crack spreads.

These crack spreads are a measure of the difference between market prices for crude oil and refined products and are a commonly used proxy within the industry to estimate or identify trends in refining margins.

Crack spreads can fluctuate significantly over time as a result of market conditions and supply and demand balances.

The NYMEX 2-1-1 crack spread is calculated using two barrels of WTI producing one barrel of NYMEX RBOB Gasoline (“RBOB”) and one barrel of NYMEX NY Harbor ULSD (“HO”).

The Mid-Continent 2-1-1 crack spread is calculated using two barrels of WTI crude oil producing one barrel of Group 3 gasoline and one barrel of Group 3 diesel.

NYMEX 2-1-1 crack spreads increased during 2019 compared to 2018 while the Mid-Continent 2-1-1 crack spreads showed a reduction.

The Group 3 2-1-1 crack spread is calculated using two barrels of WTI crude oil producing one barrel of Group 3 sub-octane gasoline and one barrel of Group 3 ultra-low sulfur diesel.

Both NYMEX 2-1-1 and Group 3 2-1-1 crack spreads decreased during 2020 compared to 2019.

The NYMEX 2-1-1 crack spread averaged $11.73 per barrel in 2020 compared to $19.93 per barrel in 2019.

The Mid-Continent 2-1-1 crack spread averaged $18.22 per barrel in 2019 compared to $18.63 per barrel in 2018.

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The tables below are presented, on a per barrel basis, for the years ended December 31, 2019, 2018, and 2017:

(1) For December 2019, the average differentials for Midland and Condensate were $0.97 and $(0.15), respectively.

The Group 3 2-1-1 crack spread averaged $9.41 per barrel in 2020 compared to $18.22 per barrel in 2019.

The tables below are presented, on a per barrel basis, by month through December 31, 2020:

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Nitrogen Fertilizer Segment

Within the Nitrogen Fertilizer Segment, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, utilization rates, and operating costs and expenses, including pet coke and natural gas feedstock costs.

Within the Nitrogen Fertilizer Segment, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, utilization, and operating costs and expenses, including pet coke and natural gas feedstock costs.

The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets.

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Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities.

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Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

2019 Market Conditions

While there is risk of short-term volatility given the inherent nature of the commodity cycle, the Company believes the long-term fundamentals for the U.S.

As a result of the overall decline in global demand for liquid transportation fuels driven by the broader impacts of the COVID-19 pandemic and actions taken by the government to mitigate its spread, ethanol production, which is a significant driver of demand for fertilizer has declined, causing many plants to reduce production or idle, evidenced by a decline in the fourth quarter 2020 average ethanol production of 10% compared to the fourth quarter of 2019 .

Additionally, due to the shift by refineries to processing more light sweet crude oil, the Coffeyville Fertilizer Facility has become more reliant on third-party pet coke as compared to pet coke produced at our Coffeyville Refinery.

Goodwill and Long-Lived Assets

As of December 31, 2019, the Nitrogen Fertilizer Segment’s Coffeyville Fertilizer Facility reporting unit had a goodwill balance of $41 million for which the estimated fair value had been in excess of carrying value based on our 2018 and 2019 assessments.

As a result of lower expectations for market conditions in the fertilizer industry, the market performance of CVR Partners’ common units, a qualitative analysis, and additional risks associated with the business, the Company concluded a triggering event had occurred that required an interim quantitative impairment assessment of goodwill for this reporting unit during the second quarter of 2020.

The results of the impairment test indicated that the carrying amount of the Coffeyville Fertilizer Facility reporting unit exceeded the estimated fair value of the reporting unit, and a full impairment of the asset was required.

Significant assumptions inherent in the valuation methodologies for goodwill include, but are not limited to, prospective financial information, growth rates, discount rates, inflationary factors, and cost of capital.

To evaluate the sensitivity of the fair value calculations for the reporting unit, the Company applied a hypothetical 1% favorable change in the weighted average cost of capital, and separately, increased the revenue projections by 10%, holding gross margins steady.

The results of these sensitivity analyses confirmed the need to record a non-cash impairment charge of $41 million during 2020.

There is no goodwill remaining as of December 31, 2020.

With the adverse economic impacts discussed above and the uncertainty surrounding the COVID-19 pandemic, there is a heightened risk that amounts recognized, including other long-lived assets, may not be recoverable.

While our assessment in 2020 did not identify the existence of an impairment indicator for the Nitrogen Fertilizer Segment’s long-lived asset groups, we continue to monitor the current environment, including the duration and breadth of the impacts that the pandemic will have on demand for our fertilizer products, to assess whether qualitative factors indicate a quantitative assessment is required.

If a quantitative test is performed, the extent to which the recoverability of our long-lived assets could be impaired is unknown.

Such impairment could have a significant adverse impact on our results of operations;

however, an impairment would have no impact on our financial condition or liquidity.

Market Indicators

While there is risk of shorter-term volatility given the inherent nature of the commodity cycle and the impacts of the global COVID-19 pandemic, the Company believes the long-term fundamentals for the U.S.

nitrogen fertilizer industry remain intact.

The Nitrogen Fertilizer Segment views the anticipated combination of (i) increasing global population, (ii) decreasing arable land per capita, (iii) continued evolution to more protein-based diets in developing countries, (iv) sustained use of corn as feedstock for the domestic production of ethanol and (v) positioning at the lower end of the global cost curve should continue to provide a solid foundation for nitrogen fertilizer producers in the U.S.

The Nitrogen Fertilizer Segment views the anticipated combination of (i) increasing global population, (ii) decreasing arable land per capita, (iii) continued evolution to more protein-based diets in developing countries, (iv) sustained use of corn as feedstock for the domestic production of ethanol, and (v) positioning at the lower end of the global cost curve should provide a solid foundation for nitrogen fertilizer producers in the U.S.

over the longer term.

During 2019, weather significantly impacted the demand for UAN and ammonia due to lack of extended dry conditions required for planting, caused by excessive rain delaying planting of corn and soybean crops.

However, as a result of this delay, there was additional demand for UAN and ammonia due to the catch up from the late start to 2019 application season, but the fall season also had excessive moisture, which limited the ability to apply nitrogen.

Consistent with the past 18 months,

While weather conditions in 2020 exhibited normal patterns, weather significantly impacted the timing of the planting season for corn and soybeans in 2019.

Due to excessive wet conditions, crops were planted later than normal in the spring which led to a late harvest of these crops in the fall of 2019.

As a result, the ammonia application season in the fall of 2019 was shortened.

This created a surplus of ammonia inventory in the market during the winter of 2019 leading into 2020.

UAN continues to be impacted by the imposition of import duties on UAN product by the European Union (the “EU”).This has resulted in shifts in UAN trade flows for product that had previously been shipped to the EU.

In 2020, natural gas prices across the world declined significantly as compared to 2019;

however, since the summer of 2020, forward market prices indicate significantly higher prices for 2021 versus historically low prices in 2020.

Natural gas is the primary feedstock for production of nitrogen fertilizers.

As a result of these factors, in the fourth quarter of 2020, the Nitrogen Fertilizer Segment has started to

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customers have been purchasing fertilizers more ratably and the expectations that harvest will be later than normal has led customers to stage their buying.

Weather (i.e., heavy rains, flooding, etc.) is going to dictate the timing of harvest and the available window for ammonia application.

Corn and soybean are two major crops planted by farmers in the U.S.

Corn crop has shown to deplete the amount of nitrogen and ammonia within the soil it is grown in, which in turn, results in a need for these nutrients to be replenished after each growing cycle.

Unlike corn, soybean is able to obtain its own nitrogen through a process known as “N fixation”.

As such, upon harvesting of soybean, the soil retains a certain amount of nitrogen which results in lower demand for nitrogen for the pursuing corn planting cycle.

Due to these factors, nitrogen fertilizer consumers generally follow a balanced corn-soybean rotational planting cycle as evident through the chart presented below for 2018 and 2017.

Due to the significant weather conditions discussed above, the 2019 planting cycle relied more heavily on corn planting to obtain sufficient crop harvests, which slightly adjusted this balance.

The relationship between the total acres planted for both corn and soybean has a direct impact on the overall demand for UAN and ammonia products.

As the number of “corn” acres increases, the market and demand for UAN and ammonia also increases.

Correspondingly, as the number of “soybean” acres increases the market and demand for UAN and ammonia decreases.

The table below shows relevant market indicators for the Nitrogen Fertilizer Segment by month through December 31, 2019:

(1) Information used within this chart was obtained from the United States Department of Agriculture, National Agricultural Statistics Service.

see an uptrend in pricing related to these products, with the expectation that product prices will continue to see an uptrend into the first quarter of 2021.

Corn and soybean are two major crops planted by farmers in North America.

Corn crops result in the depletion of the amount of nitrogen and ammonia within the soil in which it is grown, which in turn, results in the need for these nutrients to be replenished after each growing cycle.

Unlike corn, soybeans are able to obtain their own nitrogen through a process known as “N fixation.” As such, upon harvesting of soybeans, the soil retains a certain amount of nitrogen which results in lower demand for nitrogen fertilizer for the following corn planting cycle.

Due to these factors, nitrogen fertilizer consumers generally operate a balanced corn-soybean rotational planting cycle as evident through the chart presented below for 2020, 2019, and 2018.

The relationship between the total acres planted for both corn and soybean has a direct impact on the overall demand for nitrogen products.

As the number of corn acres increases, the market and demand for nitrogen also increases.

Correspondingly, as the number of soybean acres increases, the market and demand for nitrogen decreases.

Additionally, an estimated 8 billion pounds of soybean oil is expected to go towards producing cleaner biodiesel in 2020 and 2021.

Multiple refiners have announced biodiesel expansion projects for 2021 and beyond, which will only increase the demand and capacity for soybeans.

Due to the uncertainty of how these factors will truly affect the soybean market, it is not yet known how the nitrogen business will be impacted.

Ethanol is blended with gasoline to meet renewable fuel standard requirements and for its octane value.

Ethanol production has historically consumed approximately 35% of the U.S.

corn crop, so demand for corn generally rises and falls with ethanol demand.

There has been a decline in ethanol demand in 2020 due to decreased demand for transportation fuels as a result of the COVID-19 pandemic.

However, the lower ethanol demand did not alter the spring 2020 planting decisions by farmers as evidenced in the charts below.

(1) Information used within this chart was obtained from the U.S.

Energy Information Administration (“EIA”).

(2) Information used within this chart was obtained from the United States Department of Agriculture (“USDA”), National Agricultural Statistics Services.

The 2020 USDA reports on corn and soybean acres planted indicated farmers planted approximately 91.0 million acres of corn, representing an increase of 1.4% in corn acres planted as compared to 89.7 million corn acres in 2019.

Planted soybean acres are estimated to be 83.1 million acres, representing a 9.2% increase in soybean acres planted as compared to 76.1 million soybean acres in 2019.

Since the summer of 2020, adverse weather conditions in parts of the Midwest caused the USDA to lower estimated crop yields, particularly for corn.

Further, higher demand for soybeans and corn and lower grain inventories have led to a rally in crop prices for 2020 and 2021 and significantly improved farmer economics.

As a result, we experienced strong demand for ammonia for fall application and fertilizer crop inputs for the spring of 2021.

Prices for natural gas, the primary input for nitrogen fertilizer production, rose in the fourth quarter of 2020 in the U.S.

and rose even more significantly in international markets.

The increase in natural gas prices in the U.S.

has been more than offset by higher product pricing, and the competitiveness of U.S.

nitrogen producers has improved considerably.

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(2) Information used within these charts was obtained from various third-party sources including Green Markets (a Bloomberg Company), Pace Petroleum Coke Quarterly, and the U.S.

Energy Information Administration (“EIA”), amongst others.

The table below show relevant market indicators for the Nitrogen Fertilizer Segment by month through December 31, 2020:

(1) Information used within these charts was obtained from various third-party sources including Green Markets (a Bloomberg Company), Pace Petroleum Coke Quarterly, and the EIA, amongst others.

Results of Operations

The following sections should be read in conjunction with the information outlined within the previous sections of this Part II, Item 7, and the consolidated financial statements and related notes thereto in Part II, Item 8 of this Report.

The following sections should be read in conjunction with the information outlined within the previous sections of this Part II, Item 7, the consolidated financial statements, and related notes thereto in Part II, Item 8 of this Report.

Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore do not equal the sum of the operating results of the Petroleum and Nitrogen Fertilizer Segments.

Consolidated Financial Highlights

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.

Overview - The Petroleum Segment’s operating income and net income were $574 million and $559 million, respectively, for the year ended December 31, 2019.

The increases of $30 million and $48 million, respectively, are driven primarily by higher refining margins when compared to the year ended December 31, 2018.

Refining margin was $1,203 million, or $15.26 per throughput barrel, for the year ended December 31, 2019, as compared to $1,178 million, or $15.18 per throughput barrel for the year ended December 31, 2018.

The increase in refining margin of $25 million is primarily due to increased throughput volumes and lower RINs expense due to a reduction in market prices.

Further, there was a gain on the sale of the Cushing, Oklahoma crude oil terminal of $9 million (occurred in the second quarter of 2019), positively impacting the Petroleum Segment.

For the year ended December 31, 2019, the Nitrogen Fertilizer Segment net sales increased by $53 million to $404

December 31, 2020 | 45

million as a result of favorable pricing and higher volumes.

The increase in volumes was primarily attributable to a shift in demand from the fourth quarter 2018 to the second quarter of 2019 due to inclement weather.

Income Tax Expense - Income tax expense for the year ended December 31, 2019 was $129 million, or 26.2% of income before income taxes, as compared to income tax expense for the year ended December 31, 2018 of $79 million, or 17.8% of income before income taxes.

The fluctuation in income tax expense was due primarily to the decrease in non-controlling interest from the year ended December 31, 2018 to the year ended December 31, 2019.

The decrease in non-controlling interest is due to the Company’s January 29, 2019 purchase of all issued and outstanding CVR Refining common units not already owned by the Company.

Refer to Note 1 (“Organization and Nature of Business”) for a further discussion of this transaction.

The effective income tax rate varies from the federal statutory income tax rate primarily as a result of the decrease in non-controlling interest and the benefits of state income tax credits.

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above.

Overview - The Company’s operating loss and net loss were $333 million and $320 million, respectively, for the year ended December 31, 2020, decreases of $913 million and $682 million, respectively, compared to operating income and net income of $580 million and $362 million, respectively, for the year ended December 31, 2019.

These decreases were driven by declines in operating income of $855 million within the Petroleum Segment and $62 million within the Nitrogen Fertilizer Segment for the year ended December 31, 2020 compared to December 31, 2019, respectively.

Refer to our discussion of each segment’s results of operations below for further information.

Investment Income from Marketable Securities - During the first quarter of 2020, we acquired a 14.9% ownership interest in Delek US Holdings, Inc.

(“Delek”) (NYSE ticker symbol:

For the year ended December 31, 2020, we received $7 million in dividend income and recognized $34 million in unrealized gains related to the associated common shares owned.

Income Tax Expense - Income tax benefit for the year ended December 31, 2020 was $95 million, or 23.0% of loss before income taxes, as compared to income tax expense for the year ended December 31, 2019 of $129 million, or 26.2% of income before income taxes.

The fluctuation in income tax (benefit) expense was due primarily to changes in pretax income between all periods presented.

In addition, the change in the effective tax rate was due primarily to the effects of the Nitrogen Fertilizer Segment’s goodwill impairment recorded during 2020 and changes in pretax earnings attributable to noncontrolling interests between all periods presented.

Segment Financial Highlights and Results of Operations

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These inputs include crude oil, butanes, natural gasoline, ethanol, and bio-diesel (these are also known as “throughputs”).

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Refining Throughput and Production Data by Refinery

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Heavy Canadian 1,020 4,711 5,302

Other Crude Oil 5,151 — —

Other feedstocks and blendstocks 8,321 9,160 8,369

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WTI — 3 2,354

WTL 6,235 668 —

Midland WTI 1,262 10,995 10,332

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Total throughput 183,295 215,971 212,595

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Production Data Year Ended December 31,

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Total production 181,632 214,246 212,124

Liquid volume yield 97.1 % 97.3 % 96.9 %

Financial Highlights

Overview - Petroleum Segment operating income and net income for the year ended December 31, 2019 was $574 million and $559 million, a $30 million and $48 million increase respectively over the year ended December 31, 2018, driven primarily by higher refining margins and increased throughput volumes.

Light product yield (as % of crude throughput) (1) 100.3 % 98.8 % 99.0 %

Liquid volume yield (as % of total throughput) (2) 97.4 % 97.1 % 97.3 %

Distillate yield (as % of crude throughput) (3) 43.1 % 44.3 % 45.1 %

(1) Total Gasoline and Distillate divided by total Regional crude, WTI, WTL, Midland WTI, Condensate, and Heavy Canadian throughput.

(2) Total Gasoline, Distillate, and Other liquid products divided by total throughput.

(3) Total Distillate divided by total Regional crude, WTI, WTL, Midland WTI, Condensate, and Heavy Canadian throughput.

December 31, 2020 | 47

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.

Net sales for the Petroleum Segment decreased by $812 million for the year ended December 31, 2019, when compared to the year ended December 31, 2018, primarily due to lower gasoline and distillate prices.

However, the Petroleum Segment's EBITDA improved by $40 million from 2018 mainly due to decreased raw materials costs and favorable inventory impact.

(2) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.

Refining Margin - Refining margin was $1,203 million, or $15.26 per throughput barrel, for the year ended December 31, 2019, as compared to $1,178 million, or $15.18 per throughput barrel, for the year ended December 31, 2018, primarily due to increased throughput volumes and lower RINs expense resulting from a reduction in market prices, partially offset by decreased gains on derivatives in the current period.

Total throughput averaged 215,971 bpd for the year ended December 31, 2019 as compared to 212,595 bpd for the same period in 2018.

Derivative gains decreased by $127 million during 2019 compared to 2018.

Financial Highlights

Overview - Petroleum Segment operating loss and net loss for the year ended December 31, 2020 was $281 million and $271 million, respectively, compared to operating income and net income of $574 million and $559 million, respectively, for the year ended December 31, 2019.

The declines during both periods were primarily driven by lower sales volumes and unfavorable refining margins when compared to the prior periods.

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above.

Net Sales - For the year ended December 31, 2020, net sales for the Petroleum Segment decreased by $2.4 billion when compared to the year ended December 31, 2019.

This decline was primarily driven by lower sales volumes and prices as a result of reduced demand and excess supply caused by the COVID-19 pandemic.

Further, during the second quarter of 2020, the Coffeyville Refinery completed a full, planned turnaround, which began in the first quarter of 2020 and lasted 57 days.

Utilization rates were reduced at both refineries throughout the majority of the second quarter of 2020 given market dynamics and remained below full capacity in the second half of 2020 due to naphtha processing constraints driven by tighter heavy crude oil differentials favoring a very light crude slate.

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(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above.

Refining Margin - For the year ended December 31, 2020, refining margin was $298 million, or $4.44 per throughput barrel, as compared to $1.2 billion, or $15.26 per throughput barrel, for the year ended December 31, 2019.

The decrease in refining margin of $905 million was primarily driven by the 41% decline in the Group 3 2-1-1 crack spread caused by the overall economic downturn and demand destruction observed in 2020, higher costs to comply with RFS compared to 2019, and unfavorable inventory valuation impacts totaling $58 million, or 87 cents per total throughput barrel driven by lower pricing in the first half of 2020 with some offsetting increases observed through the end of the year.

This loss on inventory valuation in 2020 compares to a favorable inventory valuation impact of $43 million from the crude oil price change during 2019.

The Company recognized expense of $190 million, or $2.84 per throughput barrel, and $43 million, or 55 cents per throughput barrel, for the years ended December 31, 2020 and 2019, respectively, reflecting our costs to comply with RFS.

The significant increase in 2020 is primarily related to significantly higher RIN prices during the year ended December 31, 2020 caused by price volatility for RINs, including significant increases in market prices during the fourth quarter, and our open mark-to-market position for the 2020 compliance year of approximately 240 million RINs as of December 31, 2020.

Offsetting these reductions to refining margins were increased gains in derivatives of $55 million recognized during the year ended December 31, 2020 compared to $19 million recognized during the year ended December 31, 2019.

Our derivative gains are primarily derived from the sale of WCS barrels at Cushing, hedges of excess inventories, crack spreads swaps, and hedges entered into during 2019 that fixed WCS to WTI differentials for a portion of the WCS barrels we received in 2020.

(1) Exclusive of depreciation and amortization expense.

Direct Operating Expenses (Exclusive of Depreciation and Amortization) - Direct operating expenses on a total throughput barrel basis decreased to $4.56 per barrel from $4.62 per barrel largely due to the increased throughput volumes.

Direct operating expenses (exclusive of depreciation and amortization) were $359 million for the year ended December 31, 2019 compared to $356 million for the year ended December 31, 2018.

The increase of approximately $3 million was primarily due to increased personnel costs, partially offset by lower natural gas prices.

Depreciation and Amortization Expense - Depreciation and amortization expense increased approximately $6 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, as a result of net additions during the current year.

Capitalization of turnaround expense along with adoption of ASC 842 also contributed to this increase.

Selling, General, and Administrative Expenses, and Other - Selling, general and administrative expenses and other was $68 million for the year ended December 31, 2019 compared to $82 million for the year ended December 31, 2018.

The $14 million decrease was primarily a result of a $9 million gain on the sale of the Cushing, Oklahoma crude oil terminal in the second quarter of 2019 and a decrease in project write-offs in 2019 compared to 2018.

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Direct Operating Expenses (Exclusive of Depreciation and Amortization) - For the year ended December 31, 2020, direct operating expenses on a total throughput barrel basis increased to $4.76 per barrel from $4.56 per barrel, largely due to decreased throughput volumes with the Coffeyville Refinery being in a full, planned turnaround beginning in March 2020 and completed during April 2020, and reduced rates carried through the end of 2020.

Direct operating expenses (exclusive of depreciation and amortization) were $319 million and $359 million for the years ended December 31, 2020 and 2019, respectively.

The decrease was primarily due to lower natural gas and electricity usage from the refineries running at reduced rates, coupled with a decrease in personnel costs and repairs and maintenance expense resulting from our cost reduction efforts.

Selling, General, and Administrative Expenses, and Other - For the year ended December 31, 2020, selling, general and administrative expenses and other was $58 million compared to $68 million for the year ended December 31, 2019.

The decrease was primarily a result of lower personnel costs and other administrative expense in 2020 as compared to 2019 due to our cost reduction efforts, lower stock-based compensation expense driven by lower share prices in 2020, and a $10 million gain on the sale of Cushing tank assets reflected in the 2019 amounts.

Nitrogen Fertilizer Segment

The following tables summarize the ammonia utilization at the Coffeyville and East Dubuque facilities.

Utilization is an important measure used by management to assess operational output at each of the Nitrogen Fertilizer Segment’s Facilities.

Utilization is calculated as actual tons produced divided by capacity adjusted for planned maintenance and turnarounds.

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The presentation of our utilization is on a two-year rolling average which takes into account the impact of our planned and unplanned outages on any specific period.

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With efforts primarily focused on ammonia upgrade capabilities, we believe this measure provides a meaningful view of how well we operate.

On a consolidated basis, the Nitrogen Fertilizer Segment’s utilization decreased 2% to 93% for the two years ended December 31, 2019 compared to the two years ended December 31, 2018.

This decrease was primarily a result of ammonia storage capacity constraints at the East Dubuque Facility in the first quarter of 2019 due to inclement weather impacting customers’ ability to apply ammonia and the turnaround at the East Dubuque Facility in the fourth quarter of 2019 .

Sales and Pricing per Ton - Two of the Nitrogen Fertilizer Segment’s key operating metrics are total sales for ammonia and UAN along with the product pricing per ton realized at the gate.

Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricing measure comparable across the fertilizer industry.

Production Volumes - Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced, that was upgraded into other fertilizer products.

Net tons available for sale represent the ammonia available for sale that was not upgraded into other fertilizer products.

The table below presents these Nitrogen Fertilizer Segment metrics for the years ended December 31, 2019, 2018 and 2017:

The following table summarizes the ammonia utilization at the Coffeyville and East Dubuque Facilities.

Ammonia Utilization

Two Years Ended December 31

Consolidated 95 % 93 %

Coffeyville Fertilizer Facility 95 % 94 %

East Dubuque Fertilizer Facility 95 % 91 %

On a consolidated basis, the Nitrogen Fertilizer Segment’s utilization increased 2% to 95% for the two years ended December 31, 2020 compared to the two years ended December 31, 2019.

This increase was primarily a result of ammonia storage capacity constraints at the East Dubuque Fertilizer Facility in the first quarter of 2019 due to inclement weather

December 31, 2020 | 50

impacting customers’ ability to apply ammonia and the turnaround at the East Dubuque Fertilizer Facility in the fourth quarter of 2019.

Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into other fertilizer products.

Net tons available for sale represent the ammonia available for sale that was not upgraded into other fertilizer products.

The table below presents this metric for the years ended December 31, 2020 , 2019, and 2018.

Production Volumes

Year Ended December 31,

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UAN 1,303 1,255 1,276

Feedstock - Our Coffeyville Facility utilizes a pet coke gasification process to produce nitrogen fertilizer.

Our East Dubuque Facility uses natural gas in its production of ammonia.

Sales and Pricing per Ton - Two of the Nitrogen Fertilizer Segment’s key operating metrics are total sales for ammonia and UAN along with the product pricing per ton realized at the gate.

Total sales for ammonia and UAN were favorable due to strong demand during the spring application coupled with heavy fill orders from the summer through year end caused by higher crop prices increasing farmer demand.

Additionally, higher total utilization for 2020 increased the total products available for sale for ammonia and UAN.

This increase in production is coupled with an increased draw of ammonia and UAN inventory for 2020.

Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricing measure comparable across the fertilizer industry.

Year Ended December 31,

2020 2019 2018

Consolidated sales (thousand tons)

1,312 1,261 1,289

Consolidated product pricing at gate (dollars per ton)

$ 284 $ 392 $ 328

Feedstock - Our Coffeyville Fertilizer Facility utilizes a pet coke gasification process to produce nitrogen fertilizer.

Our East Dubuque Fertilizer Facility uses natural gas in its production of ammonia.

The table below presents these feedstocks for both facilities within the Nitrogen Fertilizer Segment for the years ended December 31, 2020, 2019, and 2018.

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2020 2019 2018

Petroleum coke used in production (thousand tons) 535 463 488

Petroleum coke (dollars per ton) $ 37.47 $ 28.41 $ 16.56

Pet coke used in production (thousand tons) 523 535 463

Pet coke (dollars per ton) $ 35.25 $ 37.47 $ 28.41

Natural gas used in production (thousands of MMBtu) (1) 8,611 6,856 7,933

Natural gas used in production (dollars per MMBtu) (1) $ 2.31 $ 2.88 $ 3.28

Natural gas cost of materials and other (thousands of MMBtu) (1) 6,961 7,122 8,052

Natural gas cost of materials and other (dollars per MMBtu) (1) $ 3.08 $ 3.15 $ 3.26

Natural gas in cost of materials and other (thousands of MMBtu) (1) 9,349 6,961 7,122

Natural gas in cost of materials and other (dollars per MMBtu) (1) $ 2.35 $ 3.08 $ 3.15

(1) The feedstock natural gas shown above does not include natural gas used for fuel.

The cost of fuel natural gas is included in Direct operating expenses (exclusive of depreciation and amortization).

The cost of natural gas used for fuel is included in Direct operating expenses (exclusive of depreciation and amortization).

Financial Highlights

Overview - For the year ended December 31, 2019, Nitrogen Fertilizer Segment operating income and net loss were $27 million and $35 million, a $21 million increase and $15 million decrease, respectively, over the year ended December 31, 2018 driven primarily by increased sales volumes and pricing.

Overview - For the year ended December 31, 2020, the Nitrogen Fertilizer Segment’s operating loss and net loss were $35 million and $98 million, respectively, a $62 million decrease in operating income and a $63 million increase in net loss, respectively, compared to the year ended December 31, 2019 driven primarily by lower net sales and the recognition of a non-

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(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.

Net Sales - The Nitrogen Fertilizer Segment’s net sales increased by $53 million to $404 million for the year ended December 31, 2019 compared to the year ended December 31, 2018.

This increase was primarily due to favorable pricing conditions which contributed $49 million in higher revenues coupled with increased sales volumes contributing $8 million as compared to the year ended December 31, 2018.

The increase in net sales was partially offset by a $3 million decrease in Urea sales.

For the years ended December 31, 2019 and 2018, net sales included $33 million and $34 million in freight revenues, respectively, and $8 million and $8 million in other revenue, respectively.

The following table demonstrates the impact of changes in sales volumes and pricing for the primary components of net sales, excluding freight, for the year ended December 31, 2019 as compared to the year ended December 31, 2018:

cash impairment of $41 million driven primarily by the lower pricing environment observed in 2020.

These impacts were offset by higher sales volumes and reductions to operating expense.

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above.

Net Sales - The Nitrogen Fertilizer Segment’s net sales decreased by $54 million to $350 million for the year ended December 31, 2020 compared to the year ended December 31, 2019.

This decrease was primarily due to unfavorable pricing conditions which contributed $99 million in lower revenues offset with increased sales volumes contributing $46 million as compared to the year ended December 31, 2019.

For the years ended December 31, 2020 and 2019, net sales included $33 million in freight revenue, respectively, and $10 million and $8 million in other revenue, respectively.

The following table demonstrates the impact of changes in sales volumes and pricing for the primary components of net sales, excluding urea products, freight, and other revenue, for the year ended December 31, 2020 as compared to the year ended December 31, 2019.

(in millions) Price

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Ammonia (36) 36

The increase in UAN and ammonia sales pricing for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to a shift in the timing of demand from the fourth quarter of 2018 to the second quarter of 2019, as customers delayed receipt of nitrogen products due to continued inclement weather.

As a result, customer demand for ammonia increased in the second quarter of 2019 as customers attempted to make up for the missed application.

In addition, the aforementioned ammonia application, coupled with freezing temperatures and flooding throughout the Midwest and Southern Plains in 2019, shifted the demand for ammonia, resulting in increased sales volumes for the year ended December 31, 2019 compared to the year ended December 31, 2018.

The decrease in Urea sales for the year ended December 31, 2019 compared to the year ended December 31, 2018 was a result of the turnaround at our East Dubuque Facility.

The decrease in UAN and ammonia sales pricing for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to competitive pricing pressures seen throughout the domestic and international markets.

For UAN, a softening natural gas market, which is the typical feedstock for nitrogen plants, shifting trade flows in UAN due to the imposition of import duties on UAN in the EU contributed to lower prices.

Additionally, lower corn prices due to decreased demand for corn for ethanol blending further contributed to lower UAN prices.

For ammonia, lower natural gas and corn prices and reduced demand for industrial uses of ammonia contributed to lower prices.

The increase in UAN and

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(1) Exclusive of depreciation and amortization expense.

ammonia sales volumes for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to strong demand during the 2020 spring application period coupled with heavy fill orders beginning in the summer of 2020 through year end.

Additionally, higher crop prices in the second half of 2020 led to greater farmer demand, which was also aided by favorable weather conditions for application.

Cost of Materials and Other - Cost of materials and other for the year ended December 31, 2020 was $91 million, compared to $94 million for the year ended December 31, 2019.

The $6 million increase was comprised primarily of a $5 million increase in pet coke costs at our Coffeyville Facility and a $6 million increase related to a draw in our ammonia and UAN inventories offset by decreased natural gas costs at our East Dubuque facility contributing $5 million.

Direct Operating Expenses (exclusive of depreciation and amortization) - For the year ended December 31, 2019, direct operating expenses (exclusive of depreciation and amortization) were $174 million as compared to $159 million for the year ended December 31, 2018.

The $15 million increase was primarily due to increased turnaround costs of $3 million, increased repairs and maintenance costs of $1 million, and an inventory draw contributing $10 million.

Depreciation and Amortization Expense - Depreciation and amortization expense increased $8 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, as a result of accelerated depreciation of certain assets, coupled with additions to property, plant, and equipment during the current year.

Selling, General, and Administrative Expenses, and Other - Selling, general and administrative expenses and other increased approximately $4 million for the year ended December 31, 2019 compared to the year ended December 31, 2018.

The increase was primarily related to asset write offs in the period contributing $3 million, coupled with increased personnel costs contributing $1 million.

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The $3 million decrease was comprised primarily of a $2 million decrease in pet coke costs at our Coffeyville Fertilizer Facility due to lower purchases of pet coke from the Coffeyville Refinery, a decrease in freight expenses and distribution costs of $1 million due to higher 2019 freight charges on sales agreements, a decrease in other feedstocks purchases of $1 million due to lower purchases of hydrogen and nitrogen, and a decrease related to a draw in our ammonia and UAN inventories contributing $1 million driven by higher crop prices leading to greater farmer demand coupled with favorable weather for application through year end, offset by an increase in purchases of third-party ammonia at the Coffeyville Fertilizer Facility of $2 million.

Non-GAAP Measures

Our management uses certain non-GAAP performance measures to evaluate current and past performance and prospects for the future to supplement our GAAP financial information presented in accordance with U.S.

Our management uses certain non-GAAP performance measures, and reconciliations to those measures, to evaluate current and past performance and prospects for the future to supplement our GAAP financial information presented in accordance with U.S.

These non-GAAP financial measures are important factors in assessing our operating results and profitability and include the performance and liquidity measures defined below.

Effective January 1, 2019, the Company revised its accounting policy method for the costs of planned major maintenance activities (turnarounds) specific to the Petroleum Segment from being expensed as incurred (the direct expensing method) to the deferral method.

Refer to Part II, Item 8, Note 2 (“Summary of Significant Accounting Policies”) for a further discussion of the impacts of this change in accounting policy.

As a result of this change in accounting policy, the non-GAAP measures of Adjusted EBITDA, Petroleum Adjusted EBITDA, Nitrogen Fertilizer Adjusted EBITDA, Adjusted Net Income (Loss), and Direct Operating Expenses per Total Throughput Barrel net of Turnaround Expense are no longer being presented.

The following are non-GAAP measures we present for the year ended December 31, 2020:

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Refining Margin - The difference between our Petroleum Segment net sales and cost of materials and other.

Refining Margin adjusted for Inventory Valuation Impacts - Refining Margin adjusted to exclude the impact of current period market price and volume fluctuations on crude oil and refined product inventories recognized in prior periods.

We record our commodity inventories on the first-in-first-out basis.

As a result, significant current period fluctuations in market prices and the volumes we hold in inventory can have favorable or unfavorable impacts on our refining margins as compared to similar metrics used by other publicly-traded companies in the refining industry.

Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts, per Throughput Barrel - Refining Margin divided by the total throughput barrels during period, which is calculated as total throughput barrels per day times the number of days in the period.

Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts, per Throughput Barrel - Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts divided by the total throughput barrels during the period, which is calculated as total throughput barrels per day times the number of days in the period.

Direct Operating Expenses per Throughput Barrel - Direct operating expenses for our Petroleum Segment divided by total throughput barrels for the period, which is calculated as total throughput barrels per day times the number of days in the period.

Free Cash Flow - Net cash provided by (used in) operating activities less capital expenditures and capitalized turnaround expenditures.

We present these measures because we believe they may help investors, analysts, lenders and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S.

GAAP results, including but not limited to our operating performance as compared to other publicly-traded companies in the refining industry, without regard to historical cost basis or financing methods and our ability to incur and service debt and fund capital expenditures.

GAAP results, including but not limited to our operating performance as compared to other publicly traded companies in the refining and fertilizer industry, without regard to historical cost basis or financing methods and our ability to incur and service debt and fund capital expenditures.

Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings and operating income.

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Factors Affecting Comparability of Our Financial Results

Refer to the “Non-GAAP Measures” section above for discussion of the changes made to the Company’s definition of certain non-GAAP measures.

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

Petroleum Segment

Coffeyville Refinery - During the fourth quarter of 2019, our Coffeyville Refinery incurred costs of $15 million related to preparations for the planned turnaround scheduled to be completed in the spring of 2020.

During the first quarter of 2018, our Coffeyville Refinery experienced an outage with its fluid catalytic cracking unit (“FCCU”) lasting 48 days.

The FCCU outage had a significant negative impact on production and sales during that period.

Wynnewood Refinery - During the first quarter of 2017, the Wynnewood Refinery underwent a turnaround on its hydrocracking unit at a cost of $13 million.

In addition, the first phase of its planned facility turnaround was completed in the fourth quarter of 2017 at a cost of $43 million.

The second phase of this turnaround was completed in the first quarter of 2019 at a cost of $24 million.

Major Scheduled Turnaround Activities

Coffeyville Refinery - Beginning in March 2020, the Coffeyville Refinery had a planned, full facility turnaround lasting 57 days, which was completed in April 2020.

During the year ended December 31, 2020, we capitalized costs of $155 million related to this planned turnaround.

During the fourth quarter of 2019, our Coffeyville Refinery capitalized costs of $15 million related to preparations for the same planned turnaround.

Wynnewood Refinery - During the first quarter of 2019, the second phase of the fourth quarter 2017 turnaround on the Wynnewood Refinery hydrocracking unit was completed and $24 million was capitalized.

Nitrogen Fertilizer Segment

During the fourth quarter of 2018, the Partnership recognized a $6 million business interruption insurance recovery associated with an outage at its Coffeyville Fertilizer Facility during 2017.

The recovery is recorded in Other income, net.

Major Scheduled Turnaround Activities

Coffeyville Fertilizer Facility - During 2018, the Coffeyville Fertilizer Facility had a planned, full facility turnaround lasting 15 days and incurred approximately $6 million in turnaround expense in the second quarter of 2018.

During 2017, the Coffeyville Fertilizer Facility’s third-party air separation unit experienced a shut down.

Paired with this shut down and subsequent operational challenges, the Coffeyville Fertilizer Facility experienced unplanned UAN downtime of 11 days during the second quarter of 2017.

East Dubuque Fertilizer Facility - During 2019, the East Dubuque Fertilizer Facility had a planned, full facility turnaround lasting 32 days and cost approximately $1 million in the third and fourth quarters of 2019.

During 2017, the East Dubuque Fertilizer Facility had a planned, full facility turnaround lasting 14 days and incurred approximately $3 million in turnaround expense in the third quarter of 2017.

Additionally, during the fourth quarter of 2017, the East Dubuque Fertilizer Facility experienced unplanned downtime totaling 12 days.

Goodwill Impairment

As a result of lower expectations for market conditions in the fertilizer industry, the market performance of the Nitrogen Fertilizer Segment’s common units, a qualitative analysis, and additional risks associated with the business, the Nitrogen Fertilizer Segment concluded a triggering event had occurred that required an interim quantitative impairment assessment of goodwill for this reporting unit as of June 30, 2020.

No such charge was recognized during 2019.

Insurance Recovery

During the fourth quarter of 2018, the Partnership recognized a $6 million business interruption insurance recovery associated with an outage at its Coffeyville Fertilizer Facility during 2017.

The recovery is recorded in Other income, net.

No such income was recognized in 2020 or 2019.

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Non-GAAP Reconciliations

Reconciliation of Net Income to EBITDA

Reconciliation of Net (Loss) Income to EBITDA

Year Ended December 31,

(in millions) 2020 2019 2018

Net income $ 362 $ 366 $ 258

Net (loss) income $ (320) $ 362 $ 366

Interest expense, net

Income tax expense (benefit)

Income tax (benefit) expense

Depreciation and amortization

EBITDA $ (7) $ 880 $ 821

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Reconciliation of Petroleum Segment Net Income to EBITDA

Reconciliation of Net Cash (Used In) Provided By Operating Activities to Free Cash Flow

Year Ended December 31,

2020 2019 2018

Net cash provided by operating activities $ 90 $ 747 $ 628

Capital expenditures (124) (121) (102)

Capitalized turnaround expenditures (159) (38) (8)

(Negative) Free cash flow $ (193) $ 588 $ 518

Reconciliation of Petroleum Segment Net (Loss) Income to EBITDA

Year Ended December 31,

(in millions) 2020 2019 2018

Petroleum net income $ 559 $ 511 $ 127

Interest expense, net 27 41 47

Petroleum net (loss) income $ (271) $ 559 $ 511

Interest (benefit) expense, net (5) 27 41

Depreciation and amortization 202 202 196

Petroleum EBITDA $ (74) $ 788 $ 748

Reconciliation of Petroleum Segment Gross Profit to Refining Margin and Refining Margin Adjusted for Inventory Valuation Impact

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Reconciliation of Petroleum Segment Gross (Loss) Profit to Refining Margin and Refining Margin Adjusted for Inventory Valuation Impact

Year Ended December 31,

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Cost of materials and other 3,288 4,765 5,602

Direct operating expenses (exclusive of depreciation and amortization as reflected below) 359 356 361

Direct operating expenses (exclusive of depreciation and amortization) 319 359 356

Depreciation and amortization 194 199 192

Direct operating expenses (exclusive of depreciation and amortization as reflected below) 359 356 361

Gross (loss) profit

(215) 645 630

Direct operating expenses (exclusive of depreciation and amortization) 319 359 356

Depreciation and amortization 194 199 192

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In order to derive the inventory valuation impact per total throughput barrel, we utilize the total dollar figures for the inventory valuation impact and divide by the number of total throughput barrels for the period.

(2) Includes an inventory valuation charge of $58 million recorded in the first quarter of 2020, as inventories were reflected at the lower of cost or net realizable value.

No adjustment was necessary for any other period in 2020, 2019, or 2018.

Reconciliation of Petroleum Segment Total Throughput Barrels

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$ 4.44 $ 15.26 $ 15.18

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Reconciliation of Petroleum Segment Refining Margin Adjusted for Inventory Valuation Impact per Total Throughput Barrel

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$ 5.31 $ 14.71 $ 15.60

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Reconciliation of Petroleum Segment Direct Operating Expenses per Total Throughput Barrel

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Our principal uses of cash are for working capital, capital expenditures, funding our debt service obligations, and paying dividends to our stockholders, as further discussed below.

We believe that our cash from operations and existing cash and cash equivalents, along with borrowings, as necessary, under CVR Partners’ AB Credit Facility and CVR Refining’s Amended and Restated ABL Credit Facility, will be sufficient to satisfy anticipated cash requirements associated with our existing operations for at least the next 12 months.

The effects of the COVID-19 pandemic have resulted in a significant and swift reduction in U.S.

economic activity.

For our industry, these effects have predominately resulted in significant changes in crude oil supply, decreases in crude oil and refined product pricing due to dramatic reductions in demand for crude oil and our refined products, primarily gasoline and jet fuel, all of which have caused significant volatility and disruption of the commodity and financial markets.

This period of extreme economic disruption, low crude oil and refined product prices, and reduced demand has and is likely to continue to have an impact on our business, results of operations, and access to sources of liquidity.

In view of the uncertainty of the depth and extent of the contraction in demand due to the COVID-19 pandemic, combined with the weaker commodity price environment, we remain focused on safe and reliable operations, cash conservation, and protecting the balance sheet.

As a result of these factors, and in light of the uncertainty of the current environment as well as potential future cash requirements of the Company, CVR Energy’s board of directors (the “Board”) reduced the cash dividend declared for the first quarter of 2020 to $0.40 per share and elected not to declare a cash dividend for the second, third, and fourth quarters of 2020.

These decisions support the Company’s continued focus on financial discipline through a balanced approach of stockholder distributions and strategic investments while providing additional flexibility to weather the uncertain environment.

The Board will continue to evaluate the economic environment, the Company’s cash needs, optimal uses of cash, and other applicable factors, and may elect to make additional changes to the Company’s dividend (if any) in future periods.

Additionally, in exercising financial discipline, we have announced the following proactive measures:

• The deferment of the majority of our growth capital spending, with the exception of the RDU Project at the Wynnewood Refinery;

• A reduction in the amount of maintenance capital expenditures in 2020 to only include those projects which are a priority to support continuing safe and reliable operations, or which we consider are critical to support future activities;

• A reduction in operational and general and administrative costs;

• For the Petroleum Segment, the deferment of the Wynnewood Refinery turnaround from the spring of 2021 to the spring of 2022, resulting in the delay of long-lead expenditures into 2021;

• For the Nitrogen Fertilizer Segment, the deferment of the Coffeyville Fertilizer Facility turnaround from the fall of 2020 to the summer of 2021 and the East Dubuque Fertilizer Facility turnaround from 2021 to 2022;

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• The application of or utilization of certain tax benefits under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) by deferring certain payroll taxes that were otherwise required to be paid in 2020, increasing our business interest deduction, and carrying back our net operating loss generated in 2020;

• The amendment of the Nitrogen Fertilizer ABL extending its term to September 30, 2022, optimizing the borrowing capacity and fee structure, and revising certain provisions to provide an improved credit facility for the Nitrogen Fertilizer Segment.

When paired with the actions outlined above and prudently managing our operating costs and capital expenditures in 2021, we believe that our cash from operations and existing cash and cash equivalents, along with borrowings, as necessary, under CVR Refining’s Amended and Restated ABL Credit Agreement (the “Petroleum ABL”) and CVR Partners’ ABL Credit Agreement, formerly the AB Credit Facility (the “Nitrogen Fertilizer ABL”), will be sufficient to satisfy anticipated cash requirements associated with our existing operations for at least the next 12 months.

However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors.

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There can be no assurance that we will seek to do any of the foregoing or that we will be able to do any of the foregoing on terms acceptable to us or at all.

The Company, and its subsidiaries, were in compliance with all covenants under their respective debt instruments as of December 31, 2019, as applicable.

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Cash Balances and Other Liquidity

As of December 31, 2019, we had consolidated cash and cash equivalents of $652 million, $393 million available under CVR Refining’s Amended and Restated ABL Credit Facility and $50 million available under CVR Partners’ AB Credit Facility.

We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.

Cash and Other Liquidity

As of December 31, 2020, we had consolidated cash and cash equivalents of $667 million, $365 million available under the Petroleum ABL and $20 million available under the Nitrogen Fertilizer ABL, we had total liquidity of approximately $1 billion as of December 31, 2020.

As of December 31, 2019, we had $652 million in cash and cash equivalents.

(in millions) December 31, 2020 December 31, 2019

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9.25% Senior Secured Notes, due June 2023

6.50% Senior Notes due April 2021

6.50% Senior Notes, due April 2021, net of current portion (1)

Unamortized discount and debt issuance costs (11) (15)

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Total CVR Refining debt $ — $ 497

5.25% Senior Notes, due February 2025 $ 600 $ —

5.75% Senior Notes, due February 2028 400 —

Unamortized debt issuance cost (6) —

Total CVR Energy debt $ 994 $ —

Total long-term debt 1,628 1,129

(1) On January 27, 2020, the Company redeemed all of the 6.50% Senior Notes due November 2022 for a redemption price equal to 101.083%, plus accrued and unpaid interest, on the redeemed notes.

The Nitrogen Fertilizer Segment has a 9.25% Senior Secured Notes due 2023, 6.50% Senior Notes due 2021, and an AB Credit Facility, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes.

Current portion of long-term debt (1) 2 —

Total long-term debt, including current portion $ 1,630 $ 1,129

(1) The 6.50% Notes, due April 2021, mature within 12 months, and, therefore, the outstanding balance of $2 million has been classified as short-term as of December 31, 2020.

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(2) On January 27, 2020 , the Company redeemed all of the 6.50% Senior Notes, due November 2022 (the “2022 Notes”) for a redemption price equal to 101.083%, plus accrued and unpaid interest, on the redeemed notes.

The Nitrogen Fertilizer Segment has 9.25% Senior Secured Notes, due 2023, 6.50% Senior Notes, due 2021, and the Nitrogen Fertilizer ABL, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes.

The Nitrogen Fertilizer Segment amended and extended the Nitrogen Fertilizer ABL in September 2020.

Refer to Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion.

As of December 31, 2019, the Petroleum Segment had a 6.50% Senior Secured Notes due 2022 (the “2022 Notes”) and an Amended and Restated ABL Credit Facility, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes.

As of December 31, 2020, the Petroleum Segment has the Petroleum ABL, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes.

As discussed above, the Company redeemed all of the 2022 Notes in January 2020.

Refer to Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion.

On January 27, 2020, CVR Energy issued $600 million in aggregate principal amount of 5.25% senior unsecured notes due 2025, (the “2025 Notes”), which mature on February 15, 2025, and $400 million in aggregate principal amount of 5.75% senior unsecured notes due 2028 (the “2028 Notes”), which mature on February 15, 2028.

On January 27, 2020, CVR Energy issued the 5.25% Senior Notes, due February 2025 (the “2025 Notes”), and 5.75% Senior Notes, due February 2028 (the “2028 Notes”).

A portion of the net proceeds from the 2025 Notes and 2028 Notes were used to fund the redemption of the 2022 Notes.

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Refer to Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion of the issuance of these new notes and the redemption of the 2022 Notes.

The Company, and its subsidiaries, were in compliance with all applicable covenants under their respective debt instruments as of December 31, 2020.

Refer to Note 6 (“Long-Term Debt and Finance Lease Obligations”) in Part II, Item 8 for further information.

Capital Spending

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We undertake growth capital spending based on the expected return on incremental capital employed.

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Our total capitalized costs for the year ended December 31, 2019, along with our estimated expenditures for 2020, by segment, are as follows:

In December 2020, our Board of Directors approved the renewable diesel project at our Wynnewood Refinery, which would convert the refinery’s hydrocracker to a renewable diesel unit capable of producing 100 million gallons of renewable diesel per year (the “RDU”).

Total estimated costs for the project are currently $110 million and completion of the RDU is expected in June 2021.

Our total capital expenditures for the year ended December 31, 2020, along with our estimated expenditures for 2021, by segment, are as follows:

(in millions) 2020 Actual

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(1) Total 2021 estimated capitalized costs include approximately $3 to 4 million of growth related projects that will require additional approvals before commencement.

(2) Includes total 2020 RDU capital expenditures of $12 million.

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(3) Includes total 2021 estimated RDU capital expenditures of between $95 and $100 million.

Our estimated capital expenditures are subject to change due to unanticipated changes in the cost, scope, and completion time for capital projects.

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We may also accelerate or defer some capital expenditures from time to time.

Capital spending for CVR Partners is determined by the board of directors of its general partner.

In the Petroleum Segment, we capitalized $38 million and $8 million of turnaround expenditures incurred during the years ended December 31, 2019 and 2018, respectively.

The next planned major turnaround within the Petroleum Segment is at the Coffeyville refinery commencing in the first quarter of 2020 with total estimated expenditures of $145 million to $155 million, of which $130 million to $140 million is expected to be incurred and capitalized in the spring of 2020.

As to the Nitrogen Fertilizer Segment, the East Dubuque facility began a major scheduled turnaround on September 14, 2019, which was completed in October.

We incurred $10 million during the year ended December 31, 2019 related to this turnaround.

Capital spending for CVR Partners is determined by the board of directors of its general partner (the “UAN GP Board”).

During the year ended December 31, 2020, the Petroleum Segment completed its scheduled turnaround at the Coffeyville Refinery in April 2020 with total capitalized expenditures of $155 million.

The next planned turnaround is at the Wynnewood Refinery, where the pre-planning expenditures are expected to start in the spring of 2021 with an estimate of $6 million expected to be incurred in 2021.

The next expected turnaround is at the Coffeyville Refinery, where pre-planning expenditures are expected to start in the fall of 2021 with an estimate of $5 million expected to be incurred in 2021.

As for the Nitrogen Fertilizer Segment, in light of the changing environment and proactive maintenance performed during several outages at the third-party owned and operated air separation unit at our Coffeyville Fertilizer Facility during the first quarter of 2020, we moved our turnaround from the previously planned time frame of the fall of 2020 to the fall of 2021, with an estimated cost of $7 to $9 million.

We will continue to monitor market conditions and make adjustments, if needed, to our current capital spending or turnaround plans.

Dividends to CVR Energy Stockholders

Dividends, if any, including the payment, amount and timing thereof, are subject to change at the discretion of the Company’s Board of Directors.

IEP, through its ownership of the Company’s common shares, is entitled to receive dividends that are declared and paid by the Company based on the number of shares held at each record date.

The following presents dividends paid to the Company's stockholders, including IEP, during the years ended December 31, 2019:

The following table presents dividends paid to the Company's stockholders, including IEP, during the year ended December 31, 2020 (amounts presented in tables below may not add to totals presented due to rounding).

Dividends Paid (in millions)

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2020 - 1st Quarter May 26, 2020 0.40 12 28 40

2019 - 2nd Quarter August 12, 2019 $ 0.75 21 54 75

2019 - 3rd Quarter November 11, 2019 $ 0.80 24 57 81

Total $ 1.20 $ 35 $ 85 $ 121

On February 19, 2020, the Company’s Board of Directors declared a cash dividend for the fourth quarter of 2019 to the Company’s stockholders of $0.80 per share, or $80 million in the aggregate.

The dividend will be paid on March 9, 2020 to stockholders of record at the close of business on March 2, 2020.

IEP will receive approximately $57 million in respect of its ownership interest in the Company’s shares.

Dividends, if any, including the payment, amount and timing thereof, are subject to change at the discretion of the Company’s Board of Directors.

During the years ended December 31, 2018 and 2017, the Company paid dividends totaling $2.50 and $2.00 per common unit, or $238 million and $174 million, respectively.

No dividends were paid for the second, third, or fourth quarters of 2020.

During the years ended December 31, 2019 and 2018, the Company paid dividends totaling $3.05 and $2.50 per common share, or $306 million and $238 million, respectively.

Of these dividends, IEP received $218 million and $179 million, respectively, for the same periods.

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Distributions to CVR Partners ’ Unitholders

The following table presents distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company, as of December 31, 2019.

Distributions Paid (in millions)

Related Period Date Paid Distribution Per

Common Unit Public Unitholders CVR Energy Total

2018 - 4th Quarter March 11, 2019 $ 0.12 $ 9 $ 5 $ 14

2019 - 1st Quarter May 13, 2019 0.07 5 3 8

2019 - 2nd Quarter August 12, 2019 0.14 11 5 16

2019 - 3rd Quarter November 11, 2019 0.07 5 3 8

Total $ 0.40 $ 30 $ 16 $ 46

Distributions, if any, including the payment, amount, and timing thereof, are subject to change at the discretion of the board of directors of CVR Partners’ general partner.

No distributions were declared for the fourth quarter of 2019.

The Partnership did not pay distributions during the year ended December 31, 2018, while during the year ended December 31, 2017, it paid a distribution of $0.02 per common unit, or $2 million.

Of this distribution, CVR Energy received $1 million.

Distributions, if any, including the payment, amount and timing thereof, are subject to change at the discretion of the UAN GP Board.

There were no distributions declared or paid by CVR Partners during the year ended December 31, 2020 related to the fourth quarter of 2019 or the first, second, and third quarters of 2020, and no distributions were declared for the fourth quarter of 2020.

During the year ended December 31, 2019, the Partnership paid distributions totaling $4.00 per common unit on a split-adjusted basis, or $45 million.

Of these distributions, CVR Energy received $16 million for the year ended December 31, 2019.

The Partnership did not pay distributions during the year ended December 31, 2018.

Capital Structure

On October 23, 2019, the Board of Directors of the Company authorized a stock repurchase program (the “Stock Repurchase Program”).

On October 23, 2019, the Board authorized a stock repurchase program (the “Stock Repurchase Program”).

The Stock Repurchase Program would enable the Company to repurchase up to $300 million of the Company’s common stock.

Repurchases under the Stock Repurchase Program may be made from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise in accordance with applicable securities laws.

The timing, price and amount of repurchases (if any) will be made at the discretion of management and are subject to market conditions as well as corporate, regulatory and other considerations.

While the Stock Repurchase Program currently has a duration of four years, it does not obligate the Company to acquire any stock and may be terminated by the Company’s Board of Directors at any time.

We did not repurchase any of our common stock during the year ended December 31, 2019.

The timing, price and amount of repurchases (if any) will be made at the discretion of management and are subject to market conditions as well as corporate, regulatory, debt maintenance and other considerations.

While the Stock Repurchase Program currently has a duration

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of four years, it does not obligate the Company to acquire any stock and may be terminated by the Board at any time.

As of December 31, 2020, the Company has not repurchased any of the Company’s common stock under the Stock Repurchase Program.

On May 6, 2020, the UAN GP Board, on behalf of CVR Partners, authorized a unit repurchase program (the “Unit Repurchase Program”).

The Unit Repurchase Program enables CVR Partners to repurchase up to $10 million of its common units.

During the year ended December 31, 2020, on a split-adjusted basis, CVR Partners repurchased 623,177 common units, on the open market at a cost of $7 million, inclusive of transaction costs, or an average price of $11.35 per common unit.

At December 31, 2020, CVR Partners had $3 million in authority remaining under the Unit Repurchase Program.

On February 22, 2021, the UAN GP Board authorized an additional $10 million for the Unit Repurchase Program.

This Unit Repurchase Program does not obligate CVR Partners to acquire any common units and may be cancelled, terminated, amended, or extended by the UAN GP Board at any time.

As a result of the unit repurchases during 2020, CVR Energy’s ownership of CVR Partners increased from 34% to 36%.

Additionally, on November 2, 2020, CVR Partners announced that the UAN GP Board had approved a 1-for-10 reverse split of CVR Partners’ common units that was completed on November 23, 2020, pursuant to which each ten common units of CVR Partners would be converted into one common unit of the Partnership (the “Reverse Unit Split”).

Following the Reverse Unit Split, the number of CVR Partners common units outstanding decreased from approximately 111 million common units to approximately 11 million common units, with proportionate adjustments to the common units under CVR Partners’ long-term incentive plan and outstanding awards thereunder.

The Reverse Unit Split did not impact CVR Energy’s ownership in CVR Partners.

The following table sets forth our consolidated cash flows for the periods indicated below:

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Financing activities 355 (642) (334)

Net (decrease) increase in cash and cash equivalents $ (16) $ 186 $ (254)

Net increase (decrease) in cash and cash equivalents and restricted cash $ 22 $ (16) $ 186

Operating Activities

The change in operating activities for the year ended December 31, 2019, as compared to the year ended December 31, 2018, was primarily due to favorable changes in working capital of $152 million, partially offset by a reduction in operating results, excluding non-cash items, of $22 million and unfavorable changes in non-current assets and liabilities of $11 million.

The change in operating activities for the year ended December 31, 2020, as compared to the year ended December 31, 2019, was primarily due to a reduction in operating results, excluding non-cash items, of $677 million, offset by favorable changes in working capital of $19 million and favorable changes in non-current assets and liabilities of $1 million.

Investing Activities

The change in investing activities for the year ended December 31, 2019, as compared to the year ended December 31, 2018, was primarily due to the receipt of $36 million of proceeds from the sale of Cushing assets net of carrying value of inventory sold as part of the divestment.

These net proceeds were partially offset by capital expenditures of $19 million and an increase in turnaround expenditures of $30 million primarily relating to preparations in the fourth quarter of 2019 for the

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Coffeyville refinery turnaround scheduled for completion in 2020 and completion of the Wynnewood refinery turnaround in the second quarter of 2019.

The change in investing activities for the year ended December 31, 2020, as compared to the year ended December 31, 2019, was primarily due to the purchase of Delek common stock for $140 million, an increase in turnaround expenditures of $121 million relating to the Coffeyville Refinery turnaround beginning in March 2020 and completed during April 2020, a decrease in proceeds from the sale of assets of $36 million, and an increase in capital expenditures of $3 million .

Financing Activities

The change in financing activities for the year ended December 31, 2019, as compared to the year ended December 31, 2018, was primarily due to $301 million in funds used to acquire the remaining CVR Refining common units not otherwise owned by us, along with increases in CVR Energy dividends and CVR Partners distributions paid to public unitholders of $68 million and $30 million, respectively, compared to 2018, partially offset by a decrease in distributions to CVR Refining public unitholders of $93 million.

Long-Term Commitments

In addition to long-term debt, we are required to make payments relating to various types of obligations.

The following table summarizes our minimum payments as of December 31, 2019 relating to contractual obligations and other commercial commitments for the five-year period following December 31, 2019 and thereafter.

Payments Due by Period

(in millions) 2020 2021 2022 2023 2024 Thereafter Total

Contractual Obligations

Long-term debt (1) $ — $ 2 $ 500 $ 645 $ — $ — $ 1,147

Operating leases (2) 16 14 11 7 4 — 52

Finance lease obligations (3) 5 6 6 6 7 35 65

Unconditional purchase obligations (4) 95 80 77 75 71 375 773

Interest payments (5) 100 99 93 34 3 8 337

Other long-term liabilities (6) 1 1 2 — — 2 6

Total contractual obligations $ 217 $ 202 $ 689 $ 767 $ 85 $ 420 $ 2,380

(1) Consists of the 2021 Notes, 2022 Notes and 2023 Notes.

Subsequent to December 31, 2019, and excluded from the table above, the Company issued the 2025 Notes and 2028 Notes and redeemed the 2022 Notes.

Refer to Part II, Item 8, Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion of the issuance of the 2025 Notes and 2028 Notes and the associated redemption of the 2022 Notes.

(2) We lease railcars, pipelines, storage, real estate, and other assets.

(3) The amount includes commitments under finance lease arrangements for three leases which include a pipeline lease, a storage and terminal equipment lease, and a bundled truck lease.

(4) The amount includes (i) commitments for petroleum products storage and petroleum transportation, (ii) electricity supply agreement, (iii) a product supply agreement, (iv) a pet coke supply agreement, (v) commitments related to our biofuels blending obligation, and (vi) various agreements for gas and gas transportation.

(5) Interest payments for our long-term debt outstanding and finance lease obligations as of December 31, 2019 and commitment fees on the unutilized commitments of the AB Credit Facility.

(6) The amount includes environmental liabilities.

Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies.

See Part I, Item 1, “Environmental Matters.”

Off-Balance Sheet Arrangements

We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.

The change in net cash provided by financing activities for the year ended December 31, 2020, as compared to the net cash used in financing activities for year ended December 31, 2019 was primarily due to increased cash inflows from the private offering of the 2025 Notes and 2028 Notes totaling $1 billion, a decrease in CVR Energy’s dividends and CVR Partners’ distributions of $185 million and $30 million, respectively, along with a decrease in cash outflows from the purchase of remaining CVR Refining units outstanding of $301 million during the year ended December 31, 2019 with no corresponding amounts paid in 2020.

Cash provided by financing activities is partially offset by payments of $500 million for the redemption

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of the outstanding 2022 Notes, $5 million in a call premium on the extinguishment of the senior notes, the repurchase of CVR Partner’ common units of $7 million, and an increase in other financing activities of $7 million.

Recent Accounting Pronouncements

Refer to Part II, Item 8, Note 2 (“Summary of Significant Accounting Policies”), of this Report for a discussion of recent accounting pronouncements applicable to us.

Critical Accounting Policies

We prepare our consolidated financial statements in accordance with GAAP.

In order to apply these principles, management must make judgments, assumptions, and estimates based on the best available information at the time.

Refer to Note 2 (“Summary of Significant Accounting Policies”) in Part II, Item 8 for a discussion of recent accounting pronouncements applicable to the Company.

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with GAAP requiring management to make judgments, assumptions, and estimates based on the best available information at the time.

Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change;

and (2) the impact of the estimates and assumptions on financial condition or operating performance is material.

Actual results could differ from the estimates and assumptions used.

Inventory Valuation

The cost of our petroleum and nitrogen fertilizer product inventories is determined under the FIFO method.

Our FIFO inventories are carried at the lower of cost or net realizable value.

We compare the estimated realizable value of inventories to their cost by product at each of our facilities.

In our Petroleum Segment, to determine the net realizable value of our inventories, we assume that crude oil and other feedstocks are converted into refined products, which requires us to make estimates regarding the refined products expected to be produced from those feedstocks and the conversion costs required to convert those feedstocks into refined products.

We also estimate the usual and customary transportation costs required to move the inventory from our plants to the appropriate points of sale, if material.

We then apply an estimated selling price to our inventories based primarily on actual prices observed subsequent to the end of the reporting period with any remaining volumes’ selling price estimated using indicative market pricing available as of the time the estimate is made.

If the net realizable value is less than cost, we recognize a loss for the difference in our statements of operations.

For our Nitrogen Fertilizer Segment, depending on inventory levels, the per-ton realizable value of our fertilizer products is estimated using pricing on in-transit orders, pricing for open, fixed-price orders that have not shipped, and, if volumes remain unaccounted for, current management pricing estimates for fertilizer products.

Management’s estimate for current pricing reflects up-to-date pricing in each facility’s market as of the end of each reporting period.

Reductions to selling prices for unreimbursed freight costs are included to arrive at net realizable value, as applicable.

During the year ended December 31, 2020, we recognized losses on inventory of $59 million to reflect net realizable value, primarily associated with our Petroleum Segment.

No amounts were recognized in 2019 or 2018.

Due to the amount and variability in volume of inventories maintained, changes in production costs, and the volatility of market pricing for our products, losses recognized to reflect inventories at the lower of cost or net realizable value could have a material impact on the Company’s results of operations.

Impairment of Long-lived Assets and Goodwill

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future expected cash flows.

If the sum of the undiscounted expected future cash flows of an asset group is less than the carrying value, including applicable liabilities, the carrying value is written down to its estimated fair value.

Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets (for example, at a refinery or fertilizer facility level).

The Company tests goodwill for impairment annually on November 1 of each year, or more frequently if events or changes in circumstances indicate the asset might be impaired.

One of our reporting units, the Coffeyville Fertilizer Facility, had a goodwill balance of $41 million at December 31, 2019.

During the second quarter of 2020, following completion of the spring planting season, the market pricing for ammonia and UAN, which are the facility’s two primary products, experienced significant pricing declines driven by updated market expectations around supply and demand fundamentals which were expected to continue into the second half of 2020.

Additionally, significant uncertainty remained as to the nature and extent of impacts to be seen on the overall demand for corn and soybean given reduced ethanol production and broader economic

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results may differ based on the accuracy of the information utilized and subsequent events.

Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Report.

Our critical accounting policies, which are listed below, could materially affect the amounts recorded in our consolidated financial statements.

• Derivative instruments and fair value of financial instruments;

• Goodwill impairment;

• Impairment of long-lived assets;

• Income taxes;

• Inventory finished goods valuation;

• Lease standard adopted by the Company for ASC 842, Leases.

Refer to Part II, Item 8, Note 2 (“Summary of Significant Accounting Policies”), of this Report for a discussion of these, and other, accounting policies.

conditions which had negatively impacted demand.

Therefore, in connection with the preparation of the financial statements for the three months ended June 30, 2020, given the pricing declines experienced in the second quarter of 2020, further muting of our near-term economic recovery assumptions, including management’s revised forecasts for product pricing in 2020 and beyond, and market price performance of our common units, we concluded an impairment indicator was present and a triggering event under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 350, Intangibles-Goodwill and Other , had occurred as of June 30, 2020 and an interim quantitative impairment assessment was performed.

Significant assumptions inherent in the valuation methodologies for goodwill included, but are not limited to, prospective financial information, growth rates, discount rates, inflationary factors, and cost of capital.

Based on the interim quantitative analysis, it was determined that the estimated fair value of the Coffeyville Fertilizer Facility reporting unit did not exceed its carrying value.

As a result, we recorded a non-cash impairment charge of $41 million during 2020.

There is no goodwill remaining as of December 31, 2020.

We performed our annual impairment reviews of goodwill for 2019 and 2018, on November 1 of each such year and concluded no impairments.

For the period ended December 31, 2019, we performed a qualitative assessment and concluded there were no events or circumstances which would trigger the performance of a quantitative analysis after reviewing all factors impacting the Coffeyville Facility reporting unit, including improved market conditions and financial results in 2019 as compared to the financial forecasts from those used in the fair value analysis at December 31, 2018, where the estimated fair value of the Coffeyville Fertilizer Facility reporting unit exceeded its carrying value by approximately 36% based upon the results of our quantitative goodwill impairment test.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis