CVR ENERGY INC (CVI) FY 2021 MD&A

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 covers the years ended December 31, 2021 and 2020 and discusses year-to-year comparisons between such periods. The discussions of the year ended December 31, 2019 and year-to-year comparisons between the years ended December 31, 2020 and 2019 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, 2020 filed on February 23, 2021, 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

Mission and Core Values

Our Mission is to be a top tier North American renewable fuels, petroleum refining, and nitrogen-based fertilizer company as measured by safe and reliable operations, superior performance and profitable growth. The foundation of how we operate is built on five core Values:

•Safety - We always put safety first. The protection of our employees, contractors and communities is paramount. We have an unwavering commitment to safety above all else. If it’s not safe, then we don’t do it.

•Environment - We care for our environment. Complying with all regulations and minimizing any environmental impact from our operations is essential. We understand our obligation to the environment and that it’s our duty to protect it.

•Integrity - We require high business ethics. We comply with the law and practice sound corporate governance. We only conduct business one way—the right way with integrity.

•Corporate Citizenship - We are proud members of the communities where we operate. We are good neighbors and know that it’s a privilege we can’t take for granted. We seek to make a positive economic and social impact through our financial donations and the contributions of time, knowledge and talent of our employees to the places where we live and work.

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

Strategic Objectives

We have outlined the following strategic objectives to drive the accomplishment of our mission:

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 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.

Achievements

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 2021 as a result of the continuing COVID-19 pandemic:

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Environmental, Social & Governance (“ESG”) Highlights

In the past year, we achieved numerous milestones through our commitment to sustainability, including environmental and safety stewardship, diversity and inclusion, community outreach and sound corporate governance. We have also established our ESG Priorities, which will serve as a guide to the development of our ESG strategy and our first ESG Report, which we target for publication in 2022 based on Sustainability Accounting Standards Board standards. The following highlights some key achievements of 2021:

We make modern life possible through the products we manufacture while contributing to the economic well-being of our employees and the communities where we operate.

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Industry Factors and Market Conditions

General Business Environment

Throughout 2020 and 2021, the COVID-19 pandemic and actions taken by governments and others in response thereto negatively impacted the worldwide economy, financial markets, and the energy and fertilizer industries. The COVID-19 pandemic 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. Vaccination efforts underway domestically and internationally provide promise for a sustained, near-term economic recovery with approximately 76% of the total U.S. population receiving at least one dose of the vaccine and 64% considered fully vaccinated, as of February 10, 2022, according to the U.S. Centers for Disease Control and Prevention. As more businesses resume operations and governmental restrictions are being lifted, there is cautious optimism that the economy will continue to recover into 2022, but it is unknown if or when the economy will return to pre-COVID-19 levels. In addition, the spread of variants of COVID-19 could cause restrictions to continue or be reinstated, which could reverse any recent improvements.

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, 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 prices 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 other refineries. Crude oil costs and the prices 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. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. 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.

As a result of government actions taken to curb the spread of COVID-19 and significant business interruptions, the demand for gasoline and diesel in the regions in which our Petroleum Segment operates declined substantially beginning at the end of the first quarter of 2020. However, building on recovery signs observed in late 2020, the U.S. market for refined products continued to show signs of recovery throughout 2021. Gasoline demand increased due to increased mobility, which is the main driver for highway travel, while the increase in diesel demand is generally a result of the opening of coastal states such as California, New York, New Jersey, and Florida to global shipping and commerce. The combination of improving demand and declining inventories led to an increase in refined products prices and crack spreads during 2021. Additionally, the U.S. demand for jet fuels has begun to recover, albeit at a slower pace than gasoline and diesel, as international and domestic business and leisure air travel increases. Jet fuel demand is approximately 85% of pre-2020 demand levels. From a global perspective, the U.S. Energy Information Administration (“EIA”) currently expects oil production will increase by more than global oil consumption, resulting in a rise of approximately 182 million barrels in 2022. However, these projections depend on the production decisions of OPEC, U.S. oil production, and the pace of oil demand growth. While the refining market is showing signs of recovery, refinery fleet utilization is still operating at lower rates, and there remains uncertainty as to whether another wave of COVID-19 cases may spur additional governmental restrictions and lock-downs in the future which could decrease the recovery efforts seen thus far in 2021.

In addition to current market conditions discussed above, we continue to be impacted by significant volatility related to compliance requirements under the Renewable Fuel Standard (“RFS”), proposed climate change laws, and regulations. The

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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 and biodiesel 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, as well as certain waivers or exemptions to which we may be entitled. Additionally, our costs to comply with the RFS depend on the consistent and timely application of the program by the Environmental Protection Agency (“EPA”), such as timely establishment of the annual renewable volume obligation (“RVO”). Due to the EPA’s unlawful failure to establish the 2021 and 2022 RVOs by the November 30, 2020 and 2021 statutory deadlines, respectively, the EPA’s delay in issuing decisions on pending small refinery hardship petitions, and the influence exerted and climate change initiatives announced by the Biden administration, among other factors, the price of RINs has been highly volatile and remains high. The price of RINs has also been impacted by the depletion of the carryover RIN bank, as demand destruction during the COVID-19 pandemic resulted in reduced ethanol blending and RIN generation did not keep pace with mandated volumes, requiring carryover RINs from the RIN bank to be used to settle blending obligations. As a result, our costs to comply with RFS (based on the 2020 RVO and proposed preliminary 2021 RVO range, for the respective periods, excluding the impacts of any exemptions or waivers to which the Petroleum Segment may be entitled) increased significantly throughout 2020 and remain significant through 2021. Additionally, the EPA’s unlawful failure to establish the 2021 and 2022 RVOs has made it difficult for regulators to forecast the demand for gasoline, diesel, and jet fuel consumption, which may drive a decrease in the availability and increase the cost of RINs.

On December 7, 2021, the EPA proposed revised 2020, preliminary 2021, and 2022 RVO ranges. In addition, a proposal to deny substantially all pending petitions for SREs was released. Although both of the previously mentioned proposals are not yet final and are pending public comments, these proposals have kept the price of RINs elevated. The EPA’s actions, and unlawful failure to act, as well as the outcome of numerous pending lawsuits relating to the RFS, could materially impact the price of RINs and existing waiver applications. As a result, we continue to expect significant volatility in the price of RINs during 2022 and such volatility could have material impacts on the Company’s results of operations, financial condition and cash flows.

In December 2020, CVR Energy’s board of directors (the “Board”) approved the renewable diesel project at our Wynnewood Refinery, which would convert the Wynnewood Refinery’s hydrocracker to a RDU expected to be capable of producing up to 100 million gallons of renewable diesel per year and approximately 170 to 180 million RINs annually. Currently, total estimated cost for the project is $170 million. Mechanical completion and startup of the RDU is expected to occur in the second quarter of 2022. The production of renewable diesel is expected to significantly reduce our net exposure to the RFS. Further, the RDU should enable us to capture additional benefits associated with the existing blenders’ tax credit currently set to expire at the end of 2022 and growing low carbon fuel standard programs across the country, with programs in place in California and Oregon and new programs anticipated to be implemented over the next few years. In May 2021, the Board approved a $10 million capital expenditure for the completion of the design and ordering of certain long-lead equipment relating to a potential project to add pretreating capabilities for the RDU at Wynnewood and for the completion of the design for a potential conversion of an existing hydrotreater at our refinery in Coffeyville, Kansas (the “Coffeyville Refinery”) to renewable diesel service. In November 2021, the Board approved the pretreater project at the Wynnewood Refinery, which is expected to be completed in the fourth quarter of 2022 at an estimated cost of $60 million. The pretreatment unit should enable us to process a wider variety of renewable diesel feedstocks and untreated soybean and corn oil at the Wynnewood Refinery, most of which have a lower carbon intensity than soybean oil and generate additional low carbon fuel standard credits. When completed, these collective renewable diesel efforts could effectively mitigate a substantial majority, if not all, of our RFS exposure. However, impacts from recent climate change initiatives under the Biden administration, actions taken by the Supreme Court, resulting administration actions under the RFS, and market conditions could significantly impact the amount by which our renewable diesel business mitigates our costs to comply with the RFS, if at all. Current plans are to convert the hydrocracker to renewable diesel service beginning in late February 2022, with expectations for the conversion to be complete in mid-April 2022. The Company anticipates the unit to be at full capacity in the second quarter of 2022, processing mainly treated soybean and corn oil.

As of December 31, 2021 and based on the 2020 RVO and proposed preliminary 2021 RVO range, we have an estimated open position (excluding the impacts of any exemptions or waivers to which we may be entitled) under the RFS for both 2020 and 2021 of approximately 370 million RINs, excluding approximately 2 million of net open, fixed-price commitments to purchase RINs, resulting in a potential liability of $494 million. The Company’s open RFS position, which does not consider open commitments expected to settle in future periods, is marked-to-market each period and thus significant market volatility, as experienced in late 2020 and in 2021, results in significant volatility in our RFS expense from period to period. We

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recognized an expense of $435 million and $190 million for the years ended December 31, 2021 and 2020, respectively, for the Petroleum Segment’s compliance with the RFS. The increase in 2021 compared to 2020 was driven by the significant increases in RINs pricing through the fourth quarter of 2021 and our open position with respect to both the 2020 and 2021 obligations (excluding the impacts of any exemptions or waivers to which we may be entitled). Of the expense recognized during the years ended December 31, 2021 and 2020, an expense of $63 million and $59 million relates to the revaluation of our net RVO position as of December 31, 2021, respectively. The revaluation represents the summation of the prior period obligation and current period commercial activities, marked at the period end market price. Based upon recent market prices of RINs in January 2022, current estimates related to other variable factors, including our anticipated blending and purchasing activities, and the impact of the open RFS positions and resolution thereof, and credits generated by the RDU, our estimated consolidated cost to comply with the RFS (without regard to any SREs we may receive) is $200 to $210 million for 2022.

Market Indicators

NYMEX WTI crude oil is an industry wide benchmark that is utilized in the market pricing of a barrel of crude oil. 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 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 increased during 2021 compared to 2020. The NYMEX 2-1-1 crack spread averaged $19.45 per barrel in 2021 compared to $11.73 per barrel in 2020. The Group 3 2-1-1 crack spread averaged $18.14 per barrel in 2021 compared to $9.41 per barrel in 2020. The benefit realized from increased cracks was partially offset by a substantial increase in RINs prices. Average monthly prices for RINs increased 170% during 2021 compared to 2020. On a blended barrel basis (calculated using applicable RVO percentages), RINs approximated $6.71 per barrel during 2021 compared to $2.48 per barrel during 2020.

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The tables below are presented, on a per barrel basis, by month through December 31, 2021:

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(1)The change over time in NYMEX - WTI, as reflected in the charts above, is illustrated below.

(2)Information used within these charts was obtained from reputable market sources, including the New York Mercantile Exchange (“NYMEX”), Intercontinental Exchange, and Argus Media, among others.

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, 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, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, local market conditions, operating levels of competing facilities, weather conditions, the availability of imports, impacts of foreign imports and foreign subsidies thereof, and the extent of government intervention in agriculture markets. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

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 corn and therefore fertilizer, declined during 2020. However, as restrictions eased during 2021, demand for ethanol for fuels blending has largely recovered to pre-COVID-19 levels, although an increase in outbreaks of any variant of COVID-19 could reverse this recovery.

Market Indicators

While there is risk of shorter-term volatility given the inherent nature of the commodity cycle, 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 and soybeans as feedstock for the domestic production of ethanol and other renewable fuels, 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.

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Corn and soybeans are two major crops planted by farmers in North America. Corn crops result in the depletion of the amount of nitrogen within the soil in which it is grown, which in turn, results in the need for this nutrient to be replenished after each growing cycle. Unlike corn, soybeans are able to obtain most of 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 2021, 2020, and 2019.

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 market and demand for nitrogen increases with increased corn acres and decreases with increased soybean acres. Additionally, an estimated 11 billion pounds of soybean oil is expected to be used in producing cleaner biodiesel in marketing year 2021/2022. Multiple refiners have announced renewable diesel expansion projects for 2022 and beyond, which will only increase the demand for soybeans and potentially for corn and canola. Due to the uncertainty of how these factors will truly affect the grain markets, it is not yet known how the nitrogen business will be impacted.

The 2021 United States Department of Agriculture (“USDA”) reports on corn and soybean acres planted indicated farmers planted 93.4 million acres of corn, representing a slight increase of 3.0% in corn acres planted as compared to 90.7 million corn acres in 2020. Planted soybean acres are estimated to be 87.2 million acres, representing a 4.6% increase in soybean acres planted as compared to 83.4 million soybean acres in 2020. The combined corn and soybean planted acres of 180.6 million is the highest in history. Based on current grain inventories and crop prices, farm economics are expected to continue to be very attractive in 2022. Further, while natural gas prices, the primary input for nitrogen fertilizer production, were at historical lows across the world in 2020, they have escalated significantly since the summer of 2021, reducing the incentive to maximize production at nitrogen fertilizer production facilities.

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 was a decline in ethanol demand that began in 2020 and continued through 2021 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 2021 planting decisions by farmers, as evidenced through the charts below.

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

(2)Information used within this chart was obtained from the USDA, National Agricultural Statistics Services.

Weather continues to be a critical variable for crop production. Grain prices rose significantly from the summer of 2020 into the spring of 2021, leading to higher planted acreage for corn and soybeans. Even with higher planted acres and trendline yields per acre, inventory levels for corn and soybeans remain below historical levels and prices have remained elevated. The higher grain prices and historically low crop inventories are leading to strong farm economics in advance of spring 2022. These conditions are expected to drive strong demand for nitrogen fertilizer, as well as other crop inputs.

Fertilizer prices have risen significantly since January 1, 2021 due to strong grain prices, the strong spring 2021 planting season, lower fertilizer supply due to nitrogen fertilizer production outages during Winter Storm Uri and Hurricane Ida and significant escalation in global feedstock costs for nitrogen fertilizer production, and other factors discussed above.

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On June 30, 2021, CF Industries Nitrogen, L.L.C., Terra Nitrogen, Limited Partnership, and Terra International (Oklahoma) LLC filed petitions with the U.S. Department of Commerce (“USDOC”) and the U.S. International Trade Commission (the “ITC”) requesting the initiation of antidumping and countervailing duty investigations on imports of UAN from Russia and Trinidad and Tobago (“Trinidad”). In August 2021, the U.S. Department of Commerce decided to pursue an investigation to determine the extent of dumping and unfair subsidies associated with imports from Russia and Trinidad, and the ITC initiated a concurrent investigation to determine whether such imports materially injure the U.S. industry. On November 30, 2021, USDOC determined that UAN imports from Russia are unfairly subsidized at rates ranging from 9.66% to 9.84% and UAN imports from Trinidad are unfairly subsidized at a rate of 1.83%. On November 30, 2021, USDOC determined that UAN imports from Russia are unfairly subsidized at rates ranging from 9.66% to 9.84% and UAN imports from Trinidad are unfairly subsidized at a rate of 1.83%. On January 27, 2022, USDOC found that Russian UAN imports are sold at less than fair value into the U.S. market at rates ranging from 9.15% to 127.19%, and that Trinidadian UAN imports at a rate of 63.08%. As a result of these determinations, USDOC will impose cash deposit requirements on imports of UAN from Russia and Trinidad, based on the preliminary rates of antidumping duties. We believe that if the antidumping and countervailing duty preliminary determinations are confirmed by USDOC, there will likely be lower amounts of imported UAN from Russia and Trinidad.

The tables below show relevant market indicators for the Nitrogen Fertilizer Segment by month through December 31, 2021:

(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.

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Results of Operations

Consolidated

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. 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 measure shown above.

Overview - The Company’s operating income and net income were $87 million and $74 million, respectively, for the year ended December 31, 2021, increases of $420 million and $394 million, respectively, compared to an operating loss and net loss of $333 million and $320 million, respectively, for the year ended December 31, 2020. These increases were driven by an improvement in operating loss of $254 million within the Petroleum Segment and $169 million within the Nitrogen Fertilizer Segment for the year ended December 31, 2021 compared to December 31, 2020. 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: DK). On June 10, 2021, the Company distributed substantially all of its holdings in Delek, of which the Company was the largest stockholder holding approximately 14.3% of Delek’s outstanding common stock, as part of a special dividend. As of December 31, 2021, the Company continued to hold other marketable securities of

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Delek, but divested these remaining interests in January 2022. Prior to the special dividend in 2021, we received no dividend income compared to $7 million of dividend income received for the year ended December 31, 2020. The Company recognized a gain of $81 million for the year ended December 31, 2021, compared to an unrealized gain based on market pricing on December 31, 2020 of $34 million for the year ended December 31, 2020.

Income Tax Expense - The income tax benefit for the year ended December 31, 2021 was $8 million, or (12.4)% of income before income taxes, as compared to income tax benefit for the year ended December 31, 2020 of $95 million, or 23.0% of loss before income taxes. The fluctuation in income tax benefit was due primarily to changes in pretax earnings and pretax earnings attributable to noncontrolling interests between all periods presented. In addition, the change in the effective tax rate was due primarily to reductions in state income tax rates enacted during 2021, changes in pretax earnings attributable to noncontrolling interests and impacts of state income tax credits generated between all periods presented.

Segment Financial Highlights and Results of Operations

Petroleum Segment

The Petroleum Segment utilizes certain inputs within its refining operations. These inputs include crude oil, butanes, natural gasoline, ethanol, and bio-diesel (these are also known as “throughputs”).

Refining Throughput and Production Data by Refinery

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(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.

Financial Highlights

Overview - Petroleum Segment operating loss and net income for the year ended December 31, 2021 were $27 million and $4 million, respectively, an improvement of $254 million and $275 million, respectively, compared to an operating loss and net loss of $281 million and $271 million, respectively, for the year ended December 31, 2020. The improvement in both operating loss and net income compared to the prior period was primarily a result of favorable refining margins resulting from improved crack spreads and inventory pricing in the current period, partially offset by increased RFS compliance costs.

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

Net Sales - For the year ended December 31, 2021, net sales for the Petroleum Segment increased by $3.1 billion when compared to the year ended December 31, 2020. This improvement was primarily related to regional inventory draws, which are driven by increased demand and, as a result, increased market pricing, as Group 3 2-1-1 crack spreads improved $8.73 for the year ended December 31, 2021 compared to the year ended December 31, 2020. Further, 2020 was impacted by a full planned turnaround at the Coffeyville Refinery, which began in February 2020, as well as reduced utilization of the Wynnewood Refinery during the same quarter given the significant gasoline demand reductions experienced late in the first quarter of 2020 as a result of the COVID-19 pandemic.

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

Refining Margin - For the year ended December 31, 2021, refining margin was $621 million, or $8.14 per throughput barrel, as compared to $298 million, or $4.44 per throughput barrel, for the year ended December 31, 2020. The increase in refining margin of $323 million was primarily driven by the 93% increase in the Group 3 2-1-1 crack spread caused by market improvements in 2021 as market demand for refined products improved compared to the economic downturn and demand destruction observed in 2020. This was combined with favorable inventory valuation impacts totaling $127 million, or $1.66 per total throughput barrel driven by increased prices for crude oil and refined products in 2021 compared to 2020. The unfavorable inventory valuation impacts of $58 million in 2020 were driven by lower crude oil prices in the first half of 2020 with some offsetting increases observed through the end of 2020. Offsetting these improvements to refining margin, the Company recognized RINs expense of $435 million, or $5.70 per throughput barrel, and $190 million, or $2.84 per throughput barrel, for the years ended December 31, 2021 and 2020, respectively, reflecting our costs to comply with RFS. The increase in 2021 is primarily related to significantly higher RIN prices during the year ended December 31, 2021 caused by price volatility

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for RINs and our open mark-to-market position for the 2020 compliance year of approximately 130 million RINs as of December 31, 2021. This was combined with derivative losses of $44 million recognized during the year ended December 31, 2021, a result of unfavorable crack spread swaps, partially offset by gains on WCS sales, compared to derivative gains of $55 million recognized during the year ended December 31, 2020, primarily resulting from WCS sales.

(1)Exclusive of depreciation and amortization expense.

Direct Operating Expenses (Exclusive of Depreciation and Amortization) - For the year ended December 31, 2021, direct operating expenses (exclusive of depreciation and amortization) were $369 million and $319 million for the years ended December 31, 2021 and 2020, respectively. The increase in the current period was primarily due to increased natural gas costs and share-based compensation. On a total throughput barrel basis, direct operating expenses increased to $4.83 per barrel from $4.76 per barrel, as a function of the increased expense in 2021, partially offset by the increase in total throughput in 2021 compared to 2020. Impacts of COVID-19 related factors and the Coffeyville Refinery’s full, planned turnaround, which began the last week of February 2020 and extended into mid-April 2020, significantly decreased throughput in 2020.

Selling, General, and Administrative Expenses, and Other - For the year ended December 31, 2021, selling, general and administrative expenses and other was $76 million compared to $58 million for the year ended December 31, 2020. The increase was primarily a result of increased personnel costs driven primarily by increased share-based and incentive-based compensation in 2021 as compared to 2020.

Nitrogen Fertilizer Segment

Utilization and Production Volumes - The following tables summarize the ammonia utilization at the Nitrogen Fertilizer Segment’s facility in Coffeyville, Kansas (the “Coffeyville Fertilizer Facility”) and East Dubuque, Illinois facility (the “East

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Dubuque Fertilizer Facility”). 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 of ammonia produced divided by capacity adjusted for planned maintenance and turnarounds.

Utilization is presented solely on ammonia production, rather than each nitrogen product, as it provides a comparative baseline against industry peers and eliminates the disparity of facility configurations for upgrade of ammonia into other nitrogen products. With efforts primarily focused on ammonia upgrade capabilities, we believe this measure provides a meaningful view of how well we operate.

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. Production for the year ended December 31, 2021 was impacted by downtime associated with the Messer air separation plant at the Coffeyville Fertilizer Facility during the months of January, June, August, October, and November of 2021 (the “Messer Outages”), downtime at the East Dubuque Fertilizer Facility due to Winter Storm Uri in February 2021, downtime at the Coffeyville Fertilizer Facility and East Dubuque Fertilizer Facility in July and September 2021, respectively, due to externally driven power outages (the “Power Outages”), and downtime at the East Dubuque Fertilizer Facility in October 2021 for an R2 repair (the “R2 Outage”). The table below presents these Nitrogen Fertilizer Segment metrics for the years ended December 31, 2021, 2020, and 2019:

On a consolidated basis, the Nitrogen Fertilizer Segment’s utilization decreased 6% to 92% for the year ended December 31, 2021 compared to the year ended December 31, 2020. This decrease was primarily due to the Messer Outages, Winter Storm Uri, the Power Outages, and the R2 Outage.

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 product sales volumes were unfavorable, driven by lower production due to the Messer Outages, Winter Storm Uri, the Power Outages, and the R2 Outage. For the year ended December 31, 2021, the lower sales volumes were more than offset by improved prices of 92% for ammonia and 74% for UAN. Ammonia and UAN sales prices were favorable primarily due to higher crop pricing coupled with lower fertilizer supply driven by production outages from Winter Storm Uri in February 2021 and Hurricane Ida in August and September 2021, as well as increased industry turnaround activity and lower global fertilizer production due to higher natural gas prices in Europe and Asia. Product pricing at the 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.

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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, 2021, 2020, and 2019.

(1)The feedstock natural gas shown above does not include natural gas used for fuel. The cost of natural gas used for fuel is included in Direct operating expenses (exclusive of depreciation and amortization).

Financial Highlights

Overview - The Nitrogen Fertilizer Segment’s operating income and net income for the year ended December 31, 2021 were $134 million and $78 million, respectively, improvements of $169 million and $176 million, respectively, compared to an operating loss and net loss of $35 million and $98 million, respectively, for the year ended December 31, 2020. Beyond the goodwill impairment of $41 million negatively impacting the 2020 period, these improvements were driven primarily by higher ammonia and UAN sales prices in 2021, partially offset by higher feedstock costs and operating expenses.

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

Net Sales - The Nitrogen Fertilizer Segment’s net sales increased by $183 million to $533 million for the year ended December 31, 2021 compared to the year ended December 31, 2020. This increase was primarily due to favorable sales pricing contributing $205 million in higher revenues, offset by decreased sales volumes, resulting in $35 million of lower revenue as compared to the year ended December 31, 2020. For the years ended December 31, 2021 and 2020, net sales included $31 million and $33 million in freight revenue, respectively, and $11 million and $10 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, 2021 as compared to the year ended December 31, 2020.

For the year ended December 31, 2021 compared to the year ended December 31, 2020, ammonia and UAN sales prices were favorable primarily due to higher crop pricing coupled with lower fertilizer supply driven by production outages from Winter Storm Uri in February 2021 and Hurricane Ida in August and September 2021, as well as increased industry turnaround activity and lower global fertilizer production due to higher natural gas prices in Europe and Asia during 2021. Total product sales volumes were unfavorable driven by lower production due to the Messer Outages, Winter Storm Uri, the Power Outages, and the R2 Outage.

Cost of Materials and Other - Cost of materials and other for the year ended December 31, 2021 was $98 million, compared to $91 million for the year ended December 31, 2020. The $7 million increase was comprised primarily of a $12 million increase in natural gas costs at our East Dubuque Fertilizer Facility due to higher natural gas prices, a $5 million increase in pet coke costs at our Coffeyville Fertilizer Facility related to higher third-party coke pricing caused by higher crude oil prices and higher pet coke pricing with Coffeyville Resources Refining & Marketing, LLC due to the UAN-indexed pricing formula, and a $2 million increase in purchases of hydrogen. These increases were offset by a decrease in freight expenses and distribution costs of $4 million due to downtime in October and November 2021 and a discontinuation of the Gavilon Railcar Lease in April 2021, a decrease related to a build in our ammonia and UAN inventories contributing $4 million, and a decrease in ammonia purchases of $3 million.

Non-GAAP Measures

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

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As a result of volatile market conditions related to the RFS during the first half of 2021 and the impacts certain significant non-cash items have on the evaluation of our operations, the Company began disclosing Adjusted EBITDA, as defined below, in the second quarter of 2021. We believe the presentation of this non-GAAP measure is meaningful to compare our operating results between periods and peer companies. All prior periods presented have been conformed to the definition below. The following are non-GAAP measures we present for the year ended December 31, 2021:

EBITDA - Consolidated net income (loss) before (i) interest expense, net, (ii) income tax expense (benefit) and (iii) depreciation and amortization expense.

Petroleum EBITDA and Nitrogen Fertilizer EBITDA - Segment net income (loss) before segment (i) interest expense, net, (ii) income tax expense (benefit), and (iii) depreciation and amortization.

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 purchased in prior periods and lower of cost or net realizable value adjustments, if applicable. 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 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.

Adjusted EBITDA, Adjusted Petroleum EBITDA and Adjusted Nitrogen Fertilizer EBITDA - EBITDA, Petroleum EBITDA and Nitrogen Fertilizer EBITDA adjusted for certain significant non-cash items and items that management believes are not attributable to or indicative of our on-going operations or that may obscure our underlying results and trends.

Adjusted Earnings (Loss) per Share - Earnings (loss) per share adjusted for certain significant non-cash items and items that management believes are not attributable to or indicative of our on-going operations or that may obscure our underlying results and trends.

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

Net Debt and Finance Lease Obligations - Net debt and finance lease obligations is total debt and finance lease obligations reduced for cash and cash equivalents.

Total Debt and Net Debt and Finance Lease Obligations to EBITDA Exclusive of Nitrogen Fertilizer - Total debt and net debt and finance lease obligations is calculated as the consolidated debt and net debt and finance lease obligations less the Nitrogen Fertilizer Segment’s debt and net debt and finance lease obligations as of the most recent period ended divided by EBITDA exclusive of the Nitrogen Fertilizer Segment for the most recent twelve-month period.

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 and fertilizer industries, 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. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures. See “Non-GAAP Reconciliations” included herein for reconciliation of these amounts. Due to rounding, numbers presented within this section may not add or equal to numbers or totals presented elsewhere within this document.

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Factors Affecting Comparability of Our Financial Results

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

Major Scheduled Turnaround Activities

Coffeyville Refinery - The Coffeyville Refinery’s next planned turnaround is expected to start in the spring of 2023, with pre-planning expenditures of $5 million expected to be incurred during 2022. During the year ended December 31, 2020, we capitalized costs of $155 million related to the planned turnaround which began in February 2020 and was completed in April 2020. During the fourth quarter of 2019, our Coffeyville Refinery capitalized costs of $15 million related to preparations for the same planned turnaround.

Wynnewood Refinery - The next planned turnaround for the Wynnewood Refinery is in the spring of 2022. During the years ended December 31, 2021, we capitalized $7 million related to pre-planning activities at the 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

Major Scheduled Turnaround Activities

Coffeyville Fertilizer Facility - The next planned turnaround at the Coffeyville Fertilizer Facility is expected to occur in the summer of 2022. Additionally, the Coffeyville Fertilizer Facility had planned downtime for certain maintenance activities, which was completed in the fourth quarter of 2021 at a cost of $2 million. For the year ended December 31, 2021, we also incurred less than $1 million for the Coffeyville Fertilizer Facility expected turnaround in the summer of 2022.

East Dubuque Fertilizer Facility - The next planned turnaround at the East Dubuque Fertilizer Facility is expected to occur in the summer of 2022. For the year ended December 31, 2021, we incurred approximately $1 million in turnaround expense related to planning for the East Dubuque Fertilizer Facility’s expected turnaround in the summer of 2022.

Goodwill Impairment

As a result of lower expectations for market conditions in the fertilizer industry during 2020, the market performance of CVR Partners’ common units, a qualitative analysis, and additional risks associated with the business, CVR Partners performed an interim quantitative impairment assessment of goodwill for the Coffeyville Facility reporting unit as of June 30, 2020. The results of the impairment test indicated the carrying amount of this reporting unit exceeded the estimated fair value, and a full, non-cash impairment charge of $41.0 million was required.

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Non-GAAP Reconciliations

Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA

Reconciliation of Basic and Diluted Earnings (Loss) per Share to Adjusted (Loss) Earnings per Share

(1)Amounts are shown after-tax, using the Company’s marginal tax rate, and are presented on a per share basis using the weighted average shares outstanding for each period.

(2)Amount is shown exclusive of noncontrolling interests.

Reconciliation of Net Cash Provided By Operating Activities to Free Cash Flow

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Reconciliation of Petroleum Segment Net Income (Loss) to EBITDA and Adjusted EBITDA

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

(1)The Petroleum Segment’s basis for determining inventory value under GAAP is First-In, First-Out (“FIFO”). Changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable inventory valuation impact when crude oil prices increase and an unfavorable inventory valuation impact when crude oil prices decrease. The inventory valuation impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. 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 the years ended December 31, 2021 or 2019 or any other period in 2020.

Reconciliation of Petroleum Segment Total Throughput Barrels

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Reconciliation of Petroleum Segment Refining Margin per Total Throughput Barrel

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

Reconciliation of Petroleum Segment Direct Operating Expenses per Total Throughput Barrel

Reconciliation of Nitrogen Fertilizer Segment Net Income (Loss) to EBITDA and Adjusted EBITDA

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Reconciliation of Total Debt and Net Debt and Finance Lease Obligations to EBITDA Exclusive of Nitrogen Fertilizer

(1)Amounts are shown inclusive of the current portion of long-term debt and finance lease obligations.

(2)Net debt represents total debt and finance lease obligations exclusive of cash and cash equivalents.

(1)Due to rounding, numbers within this table may not add or equal to totals presented.

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Liquidity and Capital Resources

Our principal source of liquidity has historically been cash from operations. 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.

The effects of the COVID-19 pandemic resulted in a reduction in U.S. economic activity during 2020 and into 2021 and, for our industry, resulted in significant changes in crude oil supply and a decline in prices, as well as decreases in refined product pricing due to reductions in demand for crude oil and our refined products, primarily gasoline and jet fuel. In February 2021, Winter Storm Uri caused unprecedented disruptions to natural gas, electricity supply and refinery operations throughout the Midwest and Gulf Coast regions. In August 2021, Hurricane Ida made landfall in Louisiana which also resulted in refinery shut-ins and upstream production disruptions in the Gulf Coast. These weather events and the related limitations to refining operations helped reduce refined product inventories and balance supply and demand throughout the region. 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.

While we believe demand for crude oil and refined products has nearly returned to pre-COVID-19 levels and commodity prices have rebounded, there is still uncertainty on the horizon as the COVID-19 vaccines are distributed and countries and states continue to monitor their efforts against the virus and virus variants. We continue to maintain our focus on safe and reliable operations, maintaining an appropriate level of cash to fund ongoing operations, and protecting the balance sheet. As a result of these factors, and in light of management’s decision to cease actively pursuing petroleum refinery acquisitions given, among other factors, the uncertainty of the current environment and other potential future cash requirements of the Company and in light of the upcoming expiration of its right to use excess proceeds pursuant to the Indenture governing the 5.25% Senior Notes due 2025 and 5.75% Senior Notes due 2028 (the “Senior Notes”), the Board elected to declare a special dividend equal to $492 million during the second quarter of 2021 comprised of cash and substantially all of its investment in Delek common stock. No quarterly dividends were declared for the fourth quarter of 2020 or the first, second and third quarters of 2021. These decisions support the Company’s continued focus on financial discipline through a balanced approach of evaluation of strategic investment opportunities and stockholder distributions while maintaining adequate capital requirements for ongoing operations throughout 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 executing financial discipline, we have successfully implemented and are maintaining the following measures:

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

•Reducing the amount of refining maintenance capital expenditures to only include those projects which are a priority to support continuing safe and reliable operations, or which we consider are required to support future activities;

•Focusing future capital allocation to high-return assets and opportunities that advance participation in the energy industry transformation;

•Continuing to focus on discipled management of operational and general and administrative cost reductions;

•For the Petroleum Segment, deferring the Wynnewood Refinery turnaround from the spring of 2021 to the spring of 2022 and deferring the Coffeyville Refinery turnaround from fall of 2021 to spring of 2023; and

•For the Nitrogen Fertilizer Segment, taking advantage of downtime to perform maintenance activities which enabled us to defer the Coffeyville Fertilizer Facility turnaround from 2021 to 2022.

When paired with the actions outlined above, we believe that our cash from operations and existing cash and cash equivalents, along with borrowings, as necessary, 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 including, but not limited to, rising material and labor costs, the costs associated with complying with the Renewable Fuel Standard’s outcome of litigation and other factors. Additionally, our ability to generate sufficient cash from our operating activities and secure additional financing depends on our future operational performance, which is subject to general economic, political, financial, competitive, and other factors, some of which may be beyond our control.

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Depending on the needs of our business, contractual limitations and market conditions, we may from time to time seek to issue equity securities, incur additional debt, issue debt securities, or redeem, repurchase, refinance, or otherwise retire our existing debt through, among other things, privately negotiated transactions, redemptions, exchange offers, or tender offers. 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.

On June 23, 2021, CVR Partners and certain of its subsidiaries completed a private offering of $550 million aggregate principal amount of 6.125% Senior Unsecured Notes due June 2028 (the “2028 UAN Notes”), which mature on June 15, 2028, and partially redeemed CVR Partners’ 9.25% Senior Notes due June 2023 (the “2023 UAN Notes”) in the amount of $550 million. On September 23, 2021 and December 22, 2021, CVR Partners redeemed an additional $15 million and $15 million, respectively, in aggregate principal of the 2023 UAN Notes. On February 22, 2022, CVR Partners redeemed the remaining $65 million in aggregate principal amount of the 2023 UAN Notes. Collectively, these transactions represent a significant and favorable change in CVR Partners’s cash flow and liquidity position, with annual savings of approximately $26 million in future interest expense, as compared to our 2020 Form 10-K. Additionally, on September 30, 2021, CVR Partners entered into a new credit agreement with an aggregate principal amount of up to $35 million with a maturity date of September 30, 2024 (the “Nitrogen Fertilizer ABL”) and terminated its $35 million ABL Credit Agreement, dated as of September 30, 2016, as amended (the “UAN 2016 ABL Credit Agreement”). Refer to Part II, Item 8 Note 6 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion. The Company, and its subsidiaries, were in compliance with all applicable covenants under their respective debt instruments as of December 31, 2021, as applicable.

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, 2021, we had total liquidity of approximately $906 million which consisted of consolidated cash and cash equivalents of $510 million, $361 million available under the Petroleum ABL and $35 million available under the Nitrogen Fertilizer ABL. As of December 31, 2020, we had $667 million in cash and cash equivalents.

(1)The call price of the 2023 UAN Notes decreased to par on June 15, 2021. On June 23, 2021, September 23, 2021, and December 22, 2021, CVR Partners redeemed $550 million, $15 million, and $15 million, respectively, of the 2023 UAN Notes, at par, plus accrued and unpaid interest on the redeemed portion. The remaining balance of $65 million is outstanding as of December 31, 2021. The $65 million outstanding balance of the 2023 UAN Notes was paid in full on February 22, 2022 at par, plus accrued and unpaid interest.

(2)The $2 million outstanding balance of the 6.50% Notes, due April 2021, was paid in full on April 15, 2021.

CVR Partners

On June 23, 2021, CVR Partners and its subsidiary, CVR Nitrogen Finance Corporation (“Finance Co.” and, together with CVR Partners, the “Issuers”), completed a private offering of $550 million aggregate principal amount of the 2028 UAN Notes. The net proceeds from the 2028 UAN Notes, plus cash on hand, were used to redeem $550 million aggregate principal amount

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of the 2023 UAN Notes. On September 23, 2021 and December 22, 2021, CVR Partners redeemed $15 million and $15 million aggregate principal amount of the outstanding 2023 UAN Notes, respectively. On September 30, 2021, CVR Partners entered into the Nitrogen Fertilizer ABL and terminated its UAN 2016 ABL Credit Agreement. As of December 31, 2021, the Nitrogen Fertilizer Segment had the remaining portion of the 2023 UAN Notes, the 2028 UAN Notes, and the Nitrogen Fertilizer ABL, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes. On February 22, 2022, CVR Partners redeemed the remaining $65 million in aggregate principal amount of the 2023 UAN Notes. Refer to Part II, Item 8 Note 6 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion.

CVR Refining

As of December 31, 2021, 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. Refer to Part II, Item 8 Note 6 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion.

CVR Energy

As of December 31, 2021, CVR Energy has the Senior Notes, the net proceeds of which may be used for general corporate purposes, which may include funding acquisitions, capital projects, and/or share repurchases or other distributions to our stockholders. Refer to Part II, Item 8 Note 6 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion.

Capital Spending

We divide capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes non-discretionary maintenance projects and projects required to comply with environmental, health, and safety regulations. Growth capital projects generally involve an expansion of existing capacity and/or a reduction in direct operating expenses. We undertake growth capital spending based on the expected return on incremental capital employed.

In December 2020, our Board approved the renewable diesel project at our Wynnewood Refinery, which would convert the refinery’s hydrocracker to a RDU capable of producing 100 million gallons of renewable diesel per year. Currently, total estimated cost for the project is $170 million. Mechanical completion and startup of the RDU is expected to occur in the second quarter of 2022. In May 2021, the Board approved a $10 million capital expenditure for the completion of the design and ordering of certain long-lead equipment relating to a potential project to add pretreating capabilities for the RDU at the Wynnewood Refinery and for the completion of the design for a potential conversion of an existing hydrotreater at the Coffeyville Refinery to renewable diesel and sustainable aviation fuel services. In November 2021, the Board approved the pretreater project at the Wynnewood Refinery, which is expected to be completed in the fourth quarter of 2022 at an estimated cost of $60 million.

Our total capital expenditures for the year ended December 31, 2021, along with our estimated expenditures for 2022, by segment, are as follows:

(1)Total 2022 estimated capitalized costs include approximately $7 million of growth related projects that will require additional approvals before commencement.

(2)Renewables reflects spending on the Wynnewood Refinery RDU project. Amounts spent in 2020 were previously reported under Other. Upon completion and meeting of certain criteria under accounting rules, Renewables is expected to be a new reportable segment. As of December 31, 2021, Renewables does not the meet the definition of a reportable segment as defined under ASC 280.

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Our estimated capital expenditures are subject to change due to unanticipated changes in the cost, scope, and completion time for capital projects. For example, we may experience unexpected changes in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of the refineries or nitrogen fertilizer facilities. 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 (the “UAN GP Board”). We will continue to monitor market conditions and make adjustments, if needed, to our current capital spending or turnaround plans.

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 for the Wynnewood Refinery is in the spring of 2022. During the years ended December 31, 2021, we capitalized $7 million related to pre-planning activities at the Wynnewood Refinery. The Coffeyville Refinery’s next planned turnaround is expected to start in the spring of 2023, with pre-planning expenditures of $5 million expected to be incurred during 2022.

The Nitrogen Fertilizer Segment has planned turnarounds scheduled at our Coffeyville Fertilizer Facility and East Dubuque Fertilizer Facility. The turnaround at our Coffeyville Fertilizer Facility is expected to occur in the summer of 2022, with an estimated cost of $10 to $13 million, and the turnaround at our East Dubuque Fertilizer Facility is also expected to commence in the summer of 2022, with an estimated cost of $13 to $15 million. Additionally, the Coffeyville Fertilizer Facility had planned downtime for certain maintenance activities, which was completed in the fourth quarter of 2021 at a cost of $2 million. For the year ended December 31, 2021, we also incurred less than $1 million and approximately $1 million, in turnaround expense related to planning for the Coffeyville Fertilizer Facility’s and East Dubuque Fertilizer Facility’s expected turnarounds in 2022, respectively.

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. No dividends were declared related to the fourth quarter of 2021, and there were no quarterly dividends declared or paid during 2021 related to the first, second, and third quarters of 2021 and fourth quarter of 2020. During the years ended December 31, 2020 and 2019, the Company paid dividends totaling $1.20 and $3.05 per common share, or $121 million and $306 million, respectively. Of these dividends, IEP received $85 million and $218 million, respectively, for the same periods.

On May 26, 2021, the Company announced a special dividend of approximately $492 million, or equivalent to $4.89 per share of the Company’s common stock, to be paid in a combination of cash (the “Cash Distribution”) and common stock of Delek held by the Company (the “Stock Distribution”). On June 10, 2021, the Company distributed an aggregate amount of approximately $241 million, or $2.40 per share of the Company’s common stock, pursuant to the Cash Distribution, and approximately 10,539,880 shares of Delek common stock, which represented approximately 14.3% of the outstanding shares of Delek common stock, pursuant to the Stock Distribution. IEP received approximately 7,464,652 shares of common stock of Delek and $171 million in cash. The Stock Distribution was recorded as a reduction to equity through a derecognition of our investment in Delek, and the Company recognized a gain of $112 million from the initial investment in Delek through the date of the Stock Distribution.

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Distributions to CVR Partners’ Unitholders

Distributions, if any, including the payment, amount and timing thereof, are subject to change at the discretion of the UAN GP Board. The following table presents distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company, as of December 31, 2021.

There were no distributions declared or paid by CVR Partners related to the first quarter of 2021 and fourth quarter of 2020, and no distributions were declared or paid during 2020. During the year ended December 31, 2019, CVR Partners 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 fourth quarter of 2021, CVR Partners, upon approval by the UAN GP Board on February 21, 2022, declared a distribution of $5.24 per common unit, or $56 million, which is payable March 14, 2022 to unitholders of record as of March 7, 2022. Of this amount, CVR Energy will receive approximately $20 million, with the remaining amount payable to public unitholders.

Capital Structure

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, debt maintenance 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 Board at any time. As of December 31, 2021, the Company has not repurchased any of the Company’s common stock under the Stock Repurchase Program.

On May 6, 2020, CVR Partners announced that 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. On February 22, 2021, the UAN GP Board authorized an additional $10 million for the Unit Repurchase Program. During the year ended December 31, 2021, CVR Partners repurchased 24,378 common units on the open market in accordance with a repurchase agreement under Rules 10b5-1 and 10b-18 of the Securities Exchange Act of 1934, as amended, at a cost of $1 million, inclusive of transaction costs, or an average price of $21.70 per common unit. During the year ended December 31, 2020, as adjusted to reflect the impact of the 1-for-10 reverse unit split of CVR Partners’s common units that was effective as of November 23, 2020, CVR Partners repurchased 623,177 common units, respectively, at a cost of $7 million, inclusive of transaction costs, or an average price of $11.35 per common unit. As of December 31, 2021, CVR Partners had $12 million in authority remaining under the Unit Repurchase Program. This Unit Repurchase Program does not obligate CVR Partners to acquire any common units and may be cancelled or terminated by the UAN GP Board at any time.

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Cash Flows

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

Operating Activities

The change in operating activities for the year ended December 31, 2021, as compared to the year ended December 31, 2020, was primarily due to a $469 million increase in EBITDA during 2021, which includes a $47 million increase in non-cash earnings on the Company’s investment in Delek in 2021 compared to 2020, as well as favorable changes in working capital of $111 million associated with the increase in crude oil prices and increase in our open RFS position and a $42 million increase in non-cash share based compensation as a result of higher market prices for CVR Partners’ units and CVR Energy’s shares in 2021 compared to 2020. This is partially offset by an increase in net non-cash deferred tax expense of $68 million, as well as a 2020 lower of cost or market inventory charge of $59 million and a $41 million non-cash impairment of goodwill recognized in 2020.

Investing Activities

The change in investing activities for the year ended December 31, 2021, as compared to the year ended December 31, 2020, was primarily due to a reduction in turnaround expenditures of $154 million in 2021 due to the Coffeyville Refinery turnaround completed in April 2020 and the purchase of Delek common stock for $140 million in the first quarter of 2020. These decreases are partially offset by an increase in capital expenditures of $100 million primarily related to the Wynnewood Refinery’s RDU in 2021 and payments for the acquisition of pipeline assets of $20 million in the first quarter of 2021.

Financing Activities

The change in net cash used in financing activities for the year ended December 31, 2021, as compared to the net cash provided by financing activities for year ended December 31, 2020 was due to the January 2020 private offering of the 5.25% Senior Notes due 2025 and 5.75% Senior Notes due 2028 totaling $1 billion, netted against the issuance was the redemption of the outstanding CVR Refining 2022 Notes in January 2020 of $500 million and call premium of $5 million. Additionally, during the second quarter of 2021, CVR Partners completed a private offering of the 2028 UAN Notes totaling $550 million and used the proceeds, plus cash on hand, to redeem a portion of the 2023 UAN Notes in the second, third, and fourth quarters of 2021. The result of these debt offerings and the respective redemptions of outstanding senior notes is a net reduction in financing activities of approximately $527 million in 2021 as compared to 2020. Further, CVR Energy paid dividends of $241 million in 2021 compared to $121 million in 2020, and CVR Partners paid cash distributions of $31 million in 2021 compared to no distributions in 2020.

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 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

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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 for the years ended December 31, 2021 and 2019. 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).

One of the reporting units associated with our Nitrogen Fertilizer Segment’s Coffeyville, Kansas facility (the “Coffeyville Fertilizer Facility”) had a goodwill balance of $41 million at December 31, 2019. During the second quarter of 2020, following the completion of the spring planting season, the market pricing for ammonia and UAN, the Nitrogen Fertilizer Segment’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 conditions which may negatively impact 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, and market price performance of CVR Partners’ common units, the Company concluded an impairment indicator was present and a triggering event under Accounting Standards Codification (“ASC”) Topic 350, Intangibles-Goodwill and Other, had occurred as of June 30, 2020. Significant assumptions inherent in the valuation methodologies for goodwill are employed and include, 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, the Company recorded a full, non-cash impairment charge of $41 million during the year ended December 31, 2020.

As there was no goodwill balance at December 31, 2021, no annual impairment review was performed. The Company performed its annual impairment review of goodwill for 2019 associated with the Coffeyville Fertilizer Facility reporting unit and concluded there were no impairments. For the period ended December 31, 2019, no events or circumstances were identified

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which would trigger the performance of a quantitative analysis after reviewing all qualitative factors impacting the Coffeyville Fertilizer Facility reporting unit, including improved market conditions, financial results, and financial forecasts from those used in the fair value analysis at December 31, 2018. For the period ended December 31, 2018, the fair value of the Coffeyville Fertilizer Facility reporting unit exceeded its carrying value by approximately 36% based upon the results of the reporting unit’s goodwill impairment test.